analysis of sand transportability in pipelines

ANALYSIS OF SAND TRANSPORTABILITY IN PIPELINES

STUDY REPORT

Author Check and Verify

07/2010 Laras Wuri Dianningrum Patria Indrayana

FO/AMB/MTH

ii

LEMBAR PENGESAHAN

Menerangkan bahwa :

Laras Wuri Dianningrum

13007075

Teknik Kimia

Fakultas Teknologi Industri

Institut Teknologi Bandung

Telah menyelesaikan,

Program On the Job Training

Di Departemen FO/AMB/MTH

TOTAL E&P INDONESIE

East Kalimantan District, Balikpapan

Telah disetujui dan disahkan

Di Balikpapan, tanggal 30 Juli 2010

Pembimbing

Patria Indrayana

Head of HRD Department

Bayu Parmadi

iii

TABLE OF CONTENTS

LEMBAR PENGESAHAN ........................................................................................................................... ii

TABLE OF CONTENTS.............................................................................................................................. iii

LIST OF TABLES........................................................................................................................................ v

LIST OF FIGURES .................................................................................................................................... vii

CHAPTER I INTRODUCTION ..................................................................................................................... 1

1.1 Background of Study .................................................................................................................. 1

1.2 Objectives ................................................................................................................................. 1

1.3 Methodology ............................................................................................................................. 2

1.4 References ................................................................................................................................ 2

CHAPTER II BEKAPAI OVERVIEW ............................................................................................................. 5

CHAPTER III LITERATURE STUDY ............................................................................................................. 8

3.1 Multiphase Flow in Pipeline ...................................................................................................... 8

3.1.1 Multiphase Flow Properties ................................................................................................... 8

3.1.2 Flow Regimes Determination in Multiphase Flow (Gas and Liquid System) .......................... 10

3.1.3 Experimental Correlation in Horizontal Pipe ........................................................................ 12

3.1.4 Empirical Correlation in Vertical Pipe ................................................................................... 13

3.1.5 Beggs and Brill Correlation................................................................................................... 17

3.2 Sand Transportability in Pipe .................................................................................................. 21

3.3 Critical Flow Velocity in Sand Transport .................................................................................. 26

3.3.1 Horizontal Pipe ..................................................................................................................... 26

3.3.2 Vertical Pipe .......................................................................................................................... 27

CHAPTER IV BEKAPAI OBSERVATION .................................................................................................... 29

4.1 Bekapai Production Network Configuration and Gas Lift......................................................... 29

4 .2 Well Head Data and Maximal Deliverable Potential in Bekapai ............................................... 30

4.3 Deposit Particle Analysis ........................................................................................................ 30

CHAPTER V BASIC CALCULATION FOR FLOW REGIME PREDICTION (COMPARISON OF METHOD) ......... 33

5.1 Empirical Correlation(Mandhane, Aziz et al. versus Beggs & Brill) .......................................... 33

5.2 OLGA versus Beggs & Brill ...................................................................................................... 33

CHAPTER VI RESULTS AND DISCUSSION ................................................................................................ 38

iv

6.1 Analysis of Sand Behavior in Correlation with Flow Regime ...................................................... 40

6.1.1 Experimental Correlation (Mandhane, Aziz et al. versus Beggs & Brill) .................................. 41

6.1.1.1 Horizontal Pipe ......................................................................................................... 41

6.1.1.2 Vertical Pipe/Upflow Risers ....................................................................................... 46

6.1.2 OLGA versus Beggs & Brill..................................................................................................... 49

6.1.2.1 Oil-Gas Flow ............................................................................................................. 51

6.1.2.1.1 8” BK-BP1................................................................................................. 51

6.1.2.1.2 12” BB-BP1............................................................................................... 54

6.1.2.1.3 6” BF-BL ................................................................................................... 57

6.1.2.1.4 6” BH-BG .................................................................................................. 60

6.1.2.1.5 12” BL-BA ................................................................................................. 63

6.1.2.2 Water-Gas Flow ......................................................................................................... 65

6.1.2.2.1 12” BL-BA.................................................................................................. 66

6.1.2.2.2 6” BH-BG................................................................................................... 68

6.1.2.2.3 6” BF-BL .................................................................................................... 71

6.1.2.2.4 6” BJ-BB .................................................................................................... 73

6.1.2.2.5 8” BK-BP1 ................................................................................................. 76

6.1.2.2.6 12” BB-BP1 ............................................................................................... 78

6.1.3 Main Finding ......................................................................................................................... 80

6.1.3.1 Experimental Correlation (Mandhane, Aziz et al. versus Beggs & Brill) ........................ 80

6.1.3.2 OLGA versus Beggs & Brill ........................................................................................... 80

6.2 Analysis of Sand Settling Condition ........................................................................................ 82

6.2.1 Horizontal Pipe ..................................................................................................................... 83

6.2.2 Vertical Pipe ......................................................................................................................... 88

6.2.3 Main Finding ........................................................................................................................ 89

CHAPTER VII CONCLUSIONS AND RECOMMENDATIONS ....................................................................... 91

7.1 Conclusions ............................................................................................................................ 91

7.2 Recommendations ................................................................................................................. 91

v

LIST OF TABLES

TABLE 2.1 Pipelines and wellheads in Bekapai area .................................................................................. 6

TABLE 3.1 Multiphase flow correlations ................................................................................................. 17

TABLE 4.1 Deposit particles from bekapai area ...................................................................................... 31

TABLE 5.1 Average pressures and temperatures in Bekapai pipelines .................................................... 33

TABLE 5.2 Pipeline geometry data ......................................................................................................... 35

TABLE 5.3 Oil composition in OLGA ........................................................................................................ 35

TABLE 5.4 Gas composition in OLGA ...................................................................................................... 36

TABLE 5.5 Flow Properties in each Bekapai pipeline ............................................................................... 36

TABLE 6.1 Flow regimes of Bekapai pipelines from Mandhane’s map..................................................... 43

TABLE 6.2 Horizontal flow regimes in Bekapai pipelines by Beggs & Brill correlation (revised) ............... 43

TABLE 6.3 Horizontal flow regimes in Bekapai pipelines by Beggs & Brill correlation (1973) ................... 45

TABLE 6.4 Flow regimes of vertical Bekapai pipelines based on Aziz and Beggs & Brill correlation .......... 48

TABLE 6.5 GWR, GOR, and water cut values of Bekapai pipelines ........................................................... 48

TABLE 6.6 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oil-

gas flow (8” BK-BP1) ............................................................................................................. 53


gas flow (12” BB-BP1) ........................................................................................................... 56


gas flow (6” BF-BL) ............................................................................................................... 59


gas flow (6” BH-BG) .............................................................................................................. 62


gas flow (12” BL-BA) ............................................................................................................. 65

TABLE 6.11 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in

water-gas flow (12” BL-BA) ................................................................................................... 68


water-gas flow (6” BH-BG) .................................................................................................... 70


water-gas flow (6” BF-BL) ..................................................................................................... 73


water-gas flow (6” BJ-BB) ..................................................................................................... 75

vi


water-gas flow (8” BK-BP1) ................................................................................................. 78


water-gas flow (12” BB-BP1) ............................................................................................... 80

TABLE 6.17 Salama versus Bekapai case ................................................................................................. 82

TABLE 6.18 Flow critical velocity in several Bekapai pipelines using Salama equation............................. 84

TABLE 6.19 Actual mixture velocity in vertical Bekapai pipeline for each particle ................................... 88

vii

LIST OF FIGURES

FIGURE 2.1 Bekapai pipeline system ....................................................................................................... 6

FIGURE 3.1 Experimental correlation catagories .................................................................................... 11

FIGURE 3.2 Mandhane’s map ................................................................................................................ 12

FIGURE 3.3 Regime characteristics in horizontal pipe ............................................................................. 13

FIGURE 3.4 Multiphase flow regime in vertical pipe .............................................................................. 14

FIGURE 3.5 Duns and Ros flow regime map ........................................................................................... 15

FIGURE 3.6 Aziz et al. map ..................................................................................................................... 16

FIGURE 3.7 Flow pattern in slurry flow................................................................................................... 22

FIGURE 3.8 Multiphase flow regime consist of liquid, gas and solid........................................................ 22

FIGURE 3.9 Schematic sand behaviors in slug with low gas superficial velocity........................................ 23

FIGURE 3.10 Sand behaviors in smooth stratified regime......................................................................... 24

FIGURE 3.11 Sand dune formation behaviors ......................................................................................... 24

FIGURE 3.12 Sand behaviors in stratified-wavy regime .......................................................................... 25

FIGURE 3.13 Sand behaviors in plug regime ........................................................................................... 25

FIGURE 3.14 Sand behaviors in slug regime ........................................................................................... 26

FIGURE 3.15 FL value vs. particle diameter, concentration as parameter ................................................ 26

FIGURE 4.1 Particles sieve analysis......................................................................................................... 30

FIGURE 5.1 OLGA model view for gas-water case ................................................................................... 37

FIGURE 6.1 Factors affeted sand transportation in pipeline ................................................................... 38

FIGURE 6.2 Flow regime determination used in this analysis .................................................................. 40

FIGURE 6.3 Mandhane’s map of Bekapai pipelines ................................................................................ 42

FIGURE 6.4 Beggs & Brill map (1973) of Bekapai pipelines ..................................................................... 44

FIGURE 6.5 Aziz et al. map of Bekapai pipelines ..................................................................................... 47

FIGURE 6.6 Flow regime, holdup, and fluid velocity at 50th section in 8”BK-BP1 (oil-gas flow) ................ 51

FIGURE 6.7 Flow regime, holdup, and fluid velocity at riser bottom in 8”BK-BP1 (oil-gas flow) ............... 51

FIGURE 6.8 Flow regime, holdup, and fluid velocity at pipe outlet in 8”BK-BP1 (oil-gas flow) ................. 52

FIGURE 6.9 Flow regime, holdup, and fluid velocity at 50th section in 12”BB-BP1 (oil-gas flow) .............. 54

FIGURE 6.10 Flow regime, holdup, and fluid velocity at riser bottom in 12”BB-BP1 (oil-gas flow) ........... 54

FIGURE 6.11 Flow regime, holdup, and fluid velocity at pipe outlet in 12”BB-BP1 (oil-gas flow) ............. 55

FIGURE 6.12 Flow regime, holdup, and fluid velocity at 50th section in 6”BF-BL (oil-gas flow) ................. 57

viii

FIGURE 6.13 Flow regime, holdup, and fluid velocity at riser bottom in 6”BF-BL (oil-gas flow) ............... 57

FIGURE 6.14 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BF-BL (oil-gas flow) ................. 58

FIGURE 6.15 Flow regime, holdup, and fluid velocity at 50th section in 6”BH-BG (oil-gas flow) ............... 60

FIGURE 6.16 Flow regime, holdup, and fluid velocity at riser bottom in 6”BH-BG (oil-gas flow) .............. 60

FIGURE 6.17 Flow regime, holdup, and fluid velocity at pipe outlet in 6”BH-BG (oil-gas flow) ................ 61

FIGURE 6.18 Flow regime, holdup, and fluid velocity at 50th section in 12”BL-BA (oil-gas flow) .............. 63

FIGURE 6.19 Flow regime, holdup, and fluid velocity at riser bottom in 12”BL-BA (oil-gas flow) ............. 63

FIGURE 6.20 Flow regime, holdup, and fluid velocity at pipe outlet in 12”BL-BA (oil-gas flow) ............... 64

FIGURE 6.21 Flow regime, holdup, and fluid velocity at 50th section in 12”BL-BA (water-gas flow) ......... 66

FIGURE 6.22 Flow regime, holdup, and fluid velocity at riser bottom in 12”BL-BA (water-gas flow) ........ 66

FIGURE 6.23 Flow regime, holdup, and fluid velocity at pipe outlet in 12”BL-BA (water-gas flow) .......... 67

FIGURE 6.24 Flow regime, holdup, and fluid velocity at 50th section in 6”BH-BG (water-gas flow) .......... 68

FIGURE 6.25 Flow regime, holdup, and fluid velocity at riser bottom in 6”BH-BG (water-gas flow) ......... 69

FIGURE 6.26 Flow regime, holdup, and fluid velocity at pipe outlet in 6”BH-BG (water-gas flow) ........... 69

FIGURE 6.27 Flow regime, holdup, and fluid velocity at 50th section in6”BF-BL (water-gas flow) ............ 71

FIGURE 6.28 Flow regime, holdup, and fluid velocity at riser bottom in 6”BF-BL (water-gas flow) .......... 71

FIGURE 6.29 Flow regime, holdup, and fluid velocity at pipe outlet in 6”BF-BL (water-gas flow)............. 72

FIGURE 6.30 Flow regime, holdup, and fluid velocity at 50th section in 6”BJ-BB (water-gas flow)............ 73

FIGURE 6.31 Flow regime, holdup, and fluid velocity at riser bottom in 6”BJ-BB (water-gas flow) .......... 74

FIGURE 6.32 Flow regime, holdup, and fluid velocity at pipe outlet in 6”BJ-BB (water-gas flow) ............. 74

FIGURE 6.33 Flow regime, holdup, and fluid velocity at 50th section in 8“BK-BP1 (water-gas flow) ......... 76

FIGURE 6.34 Flow regime, holdup, and fluid velocity at riser bottom in 8”BK-BP1 (water-gas flow)........ 77

FIGURE 6.35 Flow regime, holdup, and fluid velocity at pipe outlet in 8”BK-BP1 (water-gas flow) .......... 77

FIGURE 6.36 Flow regime, holdup, and fluid velocity at 50th section in 12”BB-BP1 (water-gas flow) ....... 78

FIGURE 6.37 Flow regime, holdup, and fluid velocity at riser bottom in 12”BB-BP1 (water-gas flow)...... 79

FIGURE 6.38 Flow regime, holdup, and fluid velocity at pipe outlet in 12”BB-BP1 (water-gas flow) ........ 79

FIGURE 6.39 Critical velocity profiles in 6” BJ-BB, BF-BL, and BH-BG ....................................................... 88

FIGURE 6.40 Range of critical velocity in several Bekapai pipelines based on particle diameter ............. 88

Analysis of Sand Transportability in Pipelines 1

CHAPTER I

INTRODUCTION

1.1 Background of Study

In recent years, sand behavior along oil and gas pipelines is one of the major problems as a

consequence of sand production. Once sand is detached, it follows the fluid stream through the

perforations and into the well. Phenomena such as sand deposition can lead to partial or complete

blockage of flowlines, enhanced pipe bottom corrosion, and trapping of pigs. These failures can

cause unexpected downtime and risk to equipment as well as personnel.

Bekapai production network includes several pipelines located under the sea to connect each

platform with Bekapai production platform (BP1). Sand particles are investigated due to corrosion

enhanced caused by bacteria in two Bekapai pipeline’s surface. Indirectly, they have supported the

existence of bacteria by creating a layer that protects bacteria from corrosion inhibitor released. This

layer is called sand bed that comes from the sand settling along pipe. When multiphase flow in pipe

reaches below its critical value, solid particles carried by flow begin to settle and form sand bed in

the bottom.

Therefore, sand control management which consists of an accurate study of the parameters such as

flow rates of gas and oil, flow patterns, pressure drop, geometry and inclination design of pipelines,

etc. is required in order to develop better understanding of the problem (e.g. sand behavior with

fluid flow inside the pipeline). It must be done to overcome the lack of information available about

sand behavior in flow, especially the relationship between flow regime and sand settling condition.

However, these things are closely related in determining sand transportation, in order to prevent the

early sand accumulation before it has an impact on the pipeline’s performance and overall systems.

1.2 Objectives

This present study is going to investigate the sand behavior in Bekapai pipelines by finding the flow

critical velocity to keep sand particles moving along the pipe and its relationship with flow regimes as

multiphase flow. The other parameters influenced the phenomena such as holdup, liquid and gas

velocities, inclination and sand properties (diameter and density) are also observed in general.


1.3 Methodology

This study was performed in the frame of 2 months on the job training using following methods:

Literature studies

OLGA training

Cases studies

1.4 References

This study was performed using following references and information:

A. From internal of TOTAL E&P INDONESIE

1. Bekapai IP Inspection Summary Report 2007

2. ST-SNP-08-002 RVP Simulation During Senipah-Peciko Local Control Network Modification

3. Bekapai Wellhead Platform Operating Manual

4. Peciko Pigging Instruction Summary (revision)

5. PRODEM Section No. V, “Fluid Flow in Pipes”

6. Bekapai Potential (Status: June 24th, 2010)

7. Bekapai Production Network Configuration and Gas Lift (Status: August 25th,2006)

8. Bekapai Production Test Summary (Status: June 24th, 2010)

9. Deposit BG-3 LS 241105 (A)

10. Deposit of ex pigging BKP to SNP_051006 (B)

11. Sieve Analysis BL 14

12. Sieve Analysis BL-6_03 May 2009 (C)

13. Sieve analysis_BK 2 S 18052009

14. Sieve analysis_BL-10LS_29.05.09

15. Sieve analysis_V-100 & 120 (LP Separator)

16. DKE/PRO Method Section, “Introduction to Multiphase Flow” by Bambang Yudhistira and Zaki

Hatmanda

17. Oil and Gas Processing Plant Design and Operation Training Course, DGEP/SCR/ED/ECP, March

22nd – April 2nd , 2004


B. From external source (books, journals, articles, etc.)

1. Aggour, M. A.; Al-Yousef, H. Y.; Al-Muraikhi, A. J., “Vertical Multiphase Flow Correlations for

High Production Rates and Large Tubulars”, SPE Production & Facilities, 1996.

2. Anselmi, Ruth; Baumeister, Alberto J.; Marquez, Katiuska C., “Review of Methods and

Correlations for the Analysis of Transport Lines with Multiphase Flow”, XVIII Gas Convention,

AVPG, Caracas, Venezuela, May 27 – 29th , 2008.

3. Beggs, H. Dale; Brill, James P., “A Study of Two Phase Flow in Inclined Pipes”, Journal of

Petroleum Technology, 1973, pp. 607-617.

4. Boriyantoro, Niels H.; Adewumi, Michael A.,”An Integrated Single-Phase/Two-Phase

Hydrodynamic Model for Predicting The fluid Flow Behavior of Gas Condensate in Pipelines”

5. Bremer, Jeff, "Pipeline Flow of Settling Slurries", Sinclair Knight Merz, 2008.

6. Brennen, C.E. 2005 . Fundamentals of Multiphase Flow. UK: Cambridge University Press.

7. Campbell, John M. 2004. Gas Conditioning and Processing Vol.1. Oklahoma, USA: John M.

Campbell Company.

8. Chang, Yvonne S.H.; Ganesan, T; Lau, K. K.,”Comparison between Empirical Correlation and

Computational Fluid Dynamics Simulation for the Pressure Gradient of Multiphase Flow”,

World Congress on Engineering 2008 Vol.1, 2008.

9. Chen, R. C., “Analysis of Homogeneous Slurry Pipe Flow”, Journal of Marine Science and

Technology Vol.2 No. 1, pp. 37-45.

10. Chien, Sze-Foo, “Settling Velocity of Irregularly Shaped Particles”, SPE Drilling and

Completion, 1994.

11. Danielson, Thomas J., ”Sand Transport Modeling in Multiphase Pipelines”, OTC 18691, 2007.

12. Doan, Q. T.; Doan, L. T.; Ali, S. M. Farouq; Oguztoreli, M.,”Sand Deposition Inside a Horizontal

Well –A Simulation Approach”, Journal of Canadian Petroleum Techology, Vol. 30, No. 10,

2000.

13. Escobedo, Joel; Mansoori, G. Ali., “Surface Tension Prediction of Liquid Mixture”, AlChE

Journal, Vol. 44, No. 10 1998, pp.2324-2332.

14. Gas Processors Suppliers Association. 2004. Engineering Data Book 12th Edition. Tulsa: Gas

Processors Suppliers Association.

15. Gorji, M.; Rostamian, M., “Analyzing the Influences of Different Parameters on Terminal

Deposit in Hydrate Slurry”, International Journal of Dynamics of Fluids Vol.2 No.1 2006, pp.

99-109.

16. Hameed, Abdul, “Pipeline Pulsing Flow of Slurries”, Open Dissertation and Theses, 1983.


17. Jimenez, Jose A.; Madse, Ole S.,"A Simple Formula to Estimate Settling Velocity of Natural

Sediments", ASCE 0733-950X, 2003, 129:2 (70).

18. Kovacs, Laszlo; Varadi, Standor, "Two Phase Flow in the Vertical Pipeline of Air Lift", Periodica

Polytechnica ser. Mech. Eng. Vol. 43, no. 1, 1999, pp. 3–18.

19. Lahiri, S.K.;Glasser, Benjamin J., "Minimize Power Consumption in Slurry Transport”,

Hydrocarbon Processing, 2008.

20. Lee, M. S.; Matousek, V.; Chung, C. K.; Lee, Y. N., ”Pipe Size Effect on Hydraulic Transport of

Jumoonjin Sand-Experiments in a Dredging Test Loop”, Terra et Aqua No.99, 2005.

21. Liss, Elizabeth, D.; Conway, Stephen L.; Zega, James A.; Glasser, Benjamin J., "Segregation of

Powders during Gravity Flow Through Vertical Pipes", Pharmaceutical Technology, 2004.

22. Maurer Engineering Inc., "Multiphase Flow Production Model, Theory and User’s Manual",

DEA 67, Phase 1, 1994.

23. McLaury, B. S.; Shirazi, S. A., “Generalization of API RP 14E for Erosive Service in Multiphase

Production”, SPE 56812, 1999.

24. Rao, Bharath, “Multiphase Flow Models Range of Applicability”, CTES, L.C. Tech Note, 1998.

25. Ruano, Angel Perez, “Sand Transportation in Horizontal and Near Horizontal Multiphase

Pipelines”,M.Sc. Thesis, Carnfield University, 2008.

26. Salama, Mamdouh M., “Sand Production Management”, OTC Proceedings, 1998.

27. Salama, Mamdouh M., “Influence of Sand Production on Design and Operating of Piping

Systems”, Corrosion 2000 Paper No. 80, 2000.

28. Sutton, Robert P., “An Improved Model for Water-Hydrocarbon Surface Tension at Reservoir

Conditions”, SPE 124968, 2009.

29. Taitel, Yehuda, “Flow Pattern Transition in Two Phase Flow”, 2nd Annual Meeting of the

Institute of Multifluid Science and Technology, 1999.

30. Tronvoll, J.; Dusseault, M.B.; Santarelli, F. J., "The Tools of Sand Management", Society of

Petroleum Engineers Inc., 2001.

31. Yuan, Hong; Zhou, Desheng, “Evaluation of Two Phase Flow Correlation and Mechanistic

Models for Pipelines at Horizontal and Inclined Upward Flow”, SPE 120281, 2009.

32. http://www.unisanet.unisa.edu.au/Resources/10809/Mine%20Ventilation%20and%20Fluid%

20Flow%20Applications/Fluid%20Applications/Slurry%20Flow.pdf

33. http://www.csupomona.edu/~tknguyen/che435/Notes/P4-fluidized.pdf

34. http://sti.srs.gov/fulltext/tr2000263/tr2000263.html

http://www.unisanet.unisa.edu.au/Resources/10809/Mine%20Ventilation%20and%20Fluid%20Flow%20Applications/Fluid%20Applications/Slurry%20Flow.pdf

http://www.unisanet.unisa.edu.au/Resources/10809/Mine%20Ventilation%20and%20Fluid%20Flow%20Applications/Fluid%20Applications/Slurry%20Flow.pdf

http://www.csupomona.edu/~tknguyen/che435/Notes/P4-fluidized.pdf

http://sti.srs.gov/fulltext/tr2000263/tr2000263.html


CHAPTER II

BEKAPAI OVERVIEW

The Bekapai Field lies offshore about 15 km from the mouth of the Mahakam River delta in East

Kalimantan, Indonesia. In partnership with Pertamina and Inpex, Total Indonesie has operated the

field since production began in 1974. The field itself is in relatively calm water of 35 m depth and

extends over an area approximately 3 x 6 km. In 2004, this field produced 2,600 BOPD oil, 10

MMSCFD associated gas, and 8,250 BWPD water. In the recent update (June 2010), Bekapai still has

potential to deliver 6,361 STBD of oil, and 18.8 MMSCFD gas.

Figure 2.1 Bekapai pipeline system

There are several manifold well head platforms in this field: BA, BB, BE, BF, BG, BH, BJ, BK, and BL.

The Central Complex consists of the set of: a well-head platform, named BA, jacket with 9 slots, a

production platform, named BP, a living quarter platform named BQ, and a remote flare on a tripod,

with an additional tripod intermediate platform. The well heads are in low pressure (LP) condition.

They consist of some wells that three of them are gas lift sources (BJ-4-SS, BF-1-SS, and BL-10-LS) and

gas lift wells (BJ-3-LS, BA-9-LS, BL-7-LS, BG-1-LS, and BF-2-SS).


The five different platforms in the central complex are interconnected by bridges. The general

arrangement is in a East-West direction so that the prevailing wind is perpendicular and provides the

best natural ventilation and so that the risks of gas cloud propagation and liquid spillage at sea are

minimised, with the living quarters platform LQ upwind the platforms handling hydrocarbons. The

central complex is permanently manned, with a maximum POB of 72. It is fitted with three boat

landings, on the South sides of BA and BP, and on the East side of LQ, and a helideck (without any

stand-by or refuelling facility) on LQ. BA is served by the control and safety systems, and the utilities

of the central complex.

Table 2.1 Pipelines and wellheads in Bekapai area

Pipeline Connected Well Diameter (inches)

BK-BP1 BK-2-SS 8

BJ-BB BJ-4-SS 6

BB-BP1 BB-6-LS, BB-9-LS, BJ-4-SS 12

BE-BA BE-3-SS 6

BF-BL BF-1-SS, BF-2-LS 6

BH-BG BH-1-SS, BH-1-LS, BH-3-S 6

BG-BL BG-6-S, BG-10-S 6

BG-BL BG-6-S, BG-10-S (oil-water only) 12

BL-BA BG-6-S, BG-10-S (gas only) 12

BL-BA BG-6-S, BG-10-S, BL-1-S, BL-6-S,

BL-9-S, BL-14-S (oil-water only)

6

Bekapai production platform (BP1) collected the oil and gas from satellites. In this platform, water is

separated and then disposed to sea. Gas and oil mixture are separated, they go then to compression

and pumping and mixed thoroughly before sent to Senipah by 12” multiphase sea line.

Detail of the process consists of three main steps: separation, oil pumping, and gas compression.

Incoming LP well effluent from MWP is received by two separators (V 100 and V 120). V 100 acts as

flow dampener only. Since the gas outlet is being closed, oil and gas leaves this vessel through oil

outlet line. Then the second separator (V 120) will make a further separation to split the oil, gas, and

water stream. Gas released from this vessel is compressed into HP level by turbine driven two-stage


centrifugal compressor (K 3020 and K 3050). Besides, oil is also pumped by series of booster (MP

210-220-230) and transfer pumps (MP 240, 250, 260) before mixed with compressed gas and

delivered to Senipah terminal.

Produced water obtained from V-120 is treated in Oily Water Treatment Unit before being

discharged to the sea. Bekapai OWTU is equipped with two skimmer tanks operating in series (T 3800

and T 3810). A cyclone (F 3850) is used to enhance oil removal of skimmer tank (T 3800) water

discharge and can be used for direct cleaning of separator (V 120) water effluent. Final oil removal

takes place in a floatator, named Wemco depurator (V 3870) which can reduce oil content to less

than 50 ppm and the water is finally disposed to the sea.


CHAPTER III

LITERATURE STUDY

3.1 Multiphase Flow in Pipeline

The most commonly employed method of transporting fluid from one point to another is to force the

fluid to flow through a piping system. Pipe of circular section is most frequently used because that

shape offers not only greater structural strength, but also greater cross sectional area per unit of wall

surface than other shape. Pipe always refer to a closed conduit of circular section and constant

internal diameter.

The same thing occurred in oil and gas transportation. The flow is classified as multiphase flow which

generally located in the part of the installations between the reservoir and the process units.

Multiphase flow are first found in wells, whether production be carried out through the tubing or

through the annulus. There is also multiphase flow in the flow lines transferring the production from

the wellheads to the primary separator or the test separator. Multiphase flow may also occur in plant

piping downstream of control valves or through heat exchanger tubes where condensation or

vaporization is achieved (Prodem V).

Multiphase flow is defined as flow in which several phases are present. The phases which can be in

presence in multiphase flow are: gas, oil or condensate, free water, methanol, glycols, additives such

as corrosion inhibitors dissolved in water, solids (sand, clay).

3.1.1 Multiphase Flow Properties

Liquid mixture density (Campbell, 2004)

For determining liquid mixture density, the below equation is used.

𝑣𝑚𝑖𝑥 = 𝑥𝑖 𝑣𝑖

Where 𝑥𝑖 = mol fraction of each component

𝑣𝑖 = molar volume of each component

𝑣𝑚𝑖𝑥 = molar volume of the mixture


Liquid mixture viscosity (Campbell, 2004)

For determining liquid mixture viscosity, the below equation is used.

𝜇𝑚𝑖𝑥 = 𝑥𝑖 (𝜇𝑖)1/3

3

Where 𝑥𝑖 = mol fraction of each component

𝜇𝑖 = component viscosity

𝜇𝑚𝑖𝑥 = viscosity of mixture in centipoise

Liquid mixture surface tension (Sutton, 2007)

For determining liquid mixture surface tension, the below equation is used.

𝜎𝑕𝑤 = 1.58 𝜌𝑤 − 𝜌𝑕 + 1.76

𝑇𝑟0.3125

4

Where 𝜌𝑤 = water density

𝜌𝑕 = oil density

𝜎𝑕𝑤 = liquid mixture surface tension

𝑇𝑟 = reduced temperature

Gas density

Compressibility factor (Z) for determine the non ideal gas is gained via S. Robertson method:

𝑥 = 𝑃𝑝𝑟 /𝑇𝑝𝑟2

𝑎 = 0.1219𝑇𝑝𝑟0.638

𝑏 = 𝑇𝑝𝑟 − 7.76 +14.75

𝑇𝑝𝑟

𝑐 = 0.3𝑥 + 0.441𝑥2

𝒁 = 𝟏 + 𝒂 𝒙 − 𝒃 (𝟏 − 𝒆𝒙𝒑 −𝒄 )

Where 𝑃𝑝𝑟 = reduced pressure

𝑇𝑝𝑟 = reduced temperature

Then the actual density of gas can be found from the following equation:

𝜌 = (𝑃)(𝑀𝑟)/(𝑍 𝑅 𝑇)

Where 𝑍 = compressibility factor

𝑅 = universal gas constant

𝑃 = absolute pressure

𝑇 = absolute temperature


𝑀𝑟 = relative molecular weight

3.1.2 Flow Regimes Determination in Multiphase Flow (Gas and Liquid System)

The determination of the expected flow regime allows the proper selection of correlations or

mechanistic model for calculating the pressure gradient and liquid hold-up. In addition, for operating

purpose it is important to know which type of flow regime is predicted at various locations of the

pipeline and obviously at the outlet. Phenomena such as erosion, corrosion and vibration depend on

the flow regime.

This object has been studied in wide range of fields and applied in many sectors especially in oil and

gas production. This is not an easy task, however, many researchers must find the exact correlation

to relate among not less than 11 parameters that affect flow regimes:

a) The liquid superficial velocity, 𝑽𝒔𝒍 [m/s] (it is customary to use the superficial velocity instead

the flow rate).

b) The gas superficial velocity, 𝑽𝒔𝒈 [𝒎/𝒔].

c) Liquid density, 𝝆𝒍 [𝒌𝒈/𝒎𝟑].

d) Gas density, 𝝆𝒈 [𝒌𝒈/𝒎𝟑].

e) Liquid viscosity, 𝝁𝒍 [𝑷𝒂.𝒔].

f) Gas viscosity, 𝝁𝒈 [𝑷𝒂.𝒔].

g) Pipe diameter, 𝑫 [𝒎].

h) Acceleration of gravity, 𝒈 [𝒎/𝒔𝟐].

i) Surface tension, 𝝈 [N/m].

j) Pipe roughness, e [m].

k) Pipe inclination, 𝜽 (Taitel, 1999) .

Theoretically, the method used for the prediction of flow pattern can be classified with respect to

two categories:

Experimental correlations

The first approach for the prediction of flow patterns is based on experimental data that are plotted

on a flow pattern map. The earliest flow regime map is attributed to Baker (1954). Many more have

since been suggested for horizontal, vertical and inclined pipes. Then they are divided into three main

catagories based on the basic assumptions and methods (Figure 3.8).


Figure 3.1 Experimental correlation catagories

Mechanistic model

In this procedure one should identify the dominant physical phenomena that cause a specific

transition. Then the physical phenomena are formulated mathematically and transition lines are

calculated and can be presented as an algebraic relation or with respect to dimensionless

coordinates. It still needs correlation and closure law for input some parameters to solve the

momentum balance equation. However, there is no guarantee that this method leads always to

correct results, but the results based on this method then extrapolation to different conditions is

much safer than those based solely on experimental correlation (Taitel, 1999).

The mechanistic model developments are divided into three categories:

a. Comprehensive Models (1st generation)

This model priors a separate prediction of flow pattern and pressure gradient prediction, for

example: Taitel & Dukler Flow pattern and Xiao et a.l (Taitel & Dukler modification).

b. Unified Models (2nd generation)

Different from the previous one, this model is considered to consist only one prediction for

determining flow pattern & pressure gradient. For example: TUFFP unified model (Zhang et al.).

c. Integrated Unified Model of Heat Transfer and Fluid Flow

Experimental correlation

Catagory A

(No slippage and no flow pattern

consideration)

Pettmann&Carpenter,Baxendel&Thomas,Fanch

er&Brown

Catagory B

(Slippage considered, no flow pattern consideration)

Hagedorn&Brown,Gray,Asheim

Catagory C

(Slippage and flow pattern consideration)

Dun&Ros,Orkiszewski,Aziz,etc


This is somewhat called “future generation” of multiphase flow modeling and until this day the

experiments and current studies are still performed.

So far those methods that had been explained are limited to the steady state flow condition. The

problem occurred when they need to be applied in real situation on field which is preferably

transient one. The mechanistic models for this case are developed by many universities and

companies like SINTEF, IFE, IFP, University of Tulsa, etc. Software like OLGA and TACITE are widely

known among the practices to solve determination of flow regime in transient flow.

3.1.3 Experimental Correlation in Horizontal Pipe

The Taitel & Dukler (1976) flow model seems the most accurate one, even if its accuracy is decreasing

for large pipeline diameters. The Taitel & Dukler approach is based on a combination of theoretical

considerations of classical fluid mechanics. But it is more difficult to solve in manual calculation, so

that this model required. Other map commonly used was developed by Gregory, Aziz, and Mandhane

for horizontal flow. It has accuracy about 70% approximately and has considered the liquid hold up

and pressure drop determination.

Figure 3.2 Mandhane’s map


The characteristic of each regime explained as follows:

Figure 3.3 Regime characteristics in horizontal pipe

The boundaries between the various flow patterns in a flow pattern map occur because a regime

becomes unstable as the boundary (effect of shear force) is approached and growth of this instability

causes transition to another flow pattern.

The other side, there are other serious difficulties with most of the existing literature on flow pattern

maps, such Taitel-Duckler’s. One of the basic fluid mechanical problems is that these maps are often

dimensional and therefore apply only to the specific pipe sizes and fluids employed by the

investigator. Also there may be several possible flow patterns whose occurence may depend on the

initial conditions, specifically on the manner in which the multiphase flow is generated (Brennen,

2005).

3.1.4 Empirical Correlation in Vertical Pipe

In particular, horizontal flow regime maps must not be used for vertical flow, and vertical flow regime

maps must not be used for horizontal flow. In vertical flow the force gravity opposes the dynamic

forces. This result in slippage therefore it exhibits some different characteristics than horizontal flow

and may be more complicated.

Dispersed Flow

Bubble

(Small gas -liquid ratio, continuous phase: liquid,

very low slip velocity)

Mist/Spray

(Very high gas flow rate, very high gas-liquid ratio,

continuous phase: gas)

Segregated Flow

Stratified

(high gas-liquid ratio, medium gas flow rate, the fraction of each section is

remain constant)

Annular

(very high gas-liquid ratio, high gas flow rate, annular

film on the wall is thickened at the bottom of pipe)

IntermittentFlow

Slug

(medium gas-liquid ratio, high liquid flow rate)

Plug

(more transition regime between stratified wavy and

slug flow/annular flow, derived from stratidied

wavy)


The gas-liquid of multiphase flow in vertical pipe are determined as follows:

a. Bubble Flow

The gas phase is distributed in the form of bubbles immersed in a continuous liquid phase.

b. Bubble - Liquid Slug Flow

As the concentration of bubbles grows by the presence of a higher quantity of gas, bubbles

group or coalesce into one whose diameter approaches the pipe diameter.

c. Transition flow, Liquid Slug –Annular

With greater flow rate, the bubbles formed in the bubble flow collapse, resulting in a sparkling

and disorderly flow of gas through the liquid that is displaced to the wall of the channel.

d. Annular - Bubble Flow

The flow takes the form of a relatively thick liquid film on the pipe wall, along with a substantial

amount of liquid carried by the gas flowing in the center of the channel.

e. Annular flow

The liquid film is formed on the wall of the tube with a central part formed by gas (Anselmi, dkk.,

2008).

Figure 3.4 Multiphase flow regimes in vertical pipe

Duns and Ros developed correlation for vertical flow of gas and liquid mixtures in wells. This

correlation is valid for a wide range of oil and gas mixtures and flow regimes. Although the

correlation is intended for using with dry oil/gas mixtures, it can also be applicable to wet mixtures

with a suitable correction. For water contents less than 10%, the Duns-Ros correlation (with a

correction factor) has been reported to work well in the bubble, slug (plug), and froth regions. The

pressure profile prediction performance of the Duns & Ros method is outlined below in relation to

the several flow variables considered:


Tubing Size. In general, the pressure drop is seen to be over predicted for a range of tubing

diameters between 1 and 3 inches.

Oil Gravity. Good predictions of the pressure profile are obtained for broad range of oil

gravities (13-56 °API).

Gas-Liquid Ratio (GLR). The pressure drop is over predicted for a wide range of GLR. The

errors become especially large (> 20%) for GLR greater than 5000.

Water-Cut. The Duns-Ros model is not applicable for multiphase flow mixtures of oil, water,

and gas. However, the correlation can be used with a suitable correction factor as mentioned

above (Rao, 1998).

Figure 3.5 Duns and Ros flow regime map

(N = Liquid Velocity Number, RN = Gas Velocity Number based on Eaton Correlation)

In Region I, at low gas numbers and high liquid numbers, one encounters a liquid with gas bubbles in

it, as long as the gas-oil ratio is relatively low and the flowing pressure gradient primarily is the static

head plus liquid friction loss.

For superficial liquid velocities less than 0,4 m/s (1,3 ft/s), increased gas flow causes the bubbles to

combine and form plugs. As gas flow increases further these plugs collapse and form slugs. In these

regions wall friction is rather negligible.


If Vsl is still less than 0,4 m/s but Vsg is about 15 m/s, or greater, the slug flow of Region II changes to

mist flow in Region III.At this point the gas becomes the continuous phase with the liquid in droplet

form and as film along the wall. In Region III wall friction is a major factor in pressure loss.

Froth flow which occurs across the lines of Regions I and II occurs at high liquid velocities, Duns and

Ros expect it to occur when Vsl is greater then 1,6 m/s. At such rates no plug or slug flow was

observed. No set flow pattern can be discerned (Campbell, 2004).

The other vertical regime map is presented by Aziz et al. This map can be seen below.

Figure 3.6 Aziz et al. map

For manual calculation, Aziz is slightly more accurate than Duns and Ros due to the regime

boundaries and calculation steps. This method is similar with Mandhane et.al because only based on

superficial velocity of gas and liquid except it has been corrected for the fluid property by applying

dimensionless numbers.


The coordinates used in the Aziz vertical map are:

𝑁𝑥 = 𝑉𝑠𝑔𝑋𝐴

𝑁𝑦 = 𝑉𝑠𝑙𝑌𝐴

𝑋𝐴 = 𝜌𝑔

𝜌𝑎

0.333

𝑌𝐴

𝑌𝐴 = 𝜌𝑙 𝜎𝑤𝑎

𝜌𝑤𝜎

0.25

Where 𝑁𝑥 , , 𝑁𝑦 , 𝑋𝐴and 𝑌𝐴 are dimensionless number

𝜎𝑤𝑎 = interfacial tension of air and water at 60oF

𝜌𝑎= air density at 60oF and 14.7 psia

3.1.5 Beggs and Brill Correlation

In fact, Beggs and Brill (1973) correlation is one of many correlations used to predict the pressure loss

in multiphase flow. Each multiphase correlation makes its own particular modifications to the

hydrostatic pressure difference and the friction pressure loss calculations, in order to make them

applicable to multiphase situations. The range of applicability of the multiphase flow models is

dependent on several factors such as, tubing size or diameter, oil gravity, gas-liquid ratio, and two-

phase flow with or without water-cut. The effect of every factor on estimating the pressure profile in

a well is discussed separately for all the multiphase models considered. A reasonably good

performance of the multiphase flow models is considered to have a relative error (between the

measured and predicted values of the pressure profile) less than or equal to 20% (Rao, 1998).

In general, all multiphase correlations are essentially two phases (gas-liquid) and not three phases

(gas, water, liquid). Accordingly, the oil and water phases are combined, and treated as a pseudo

single liquid phase, while gas is considered a separate phase. The Beggs & Brill correlation is

developed for tubing strings in inclined wells and pipelines for hilly terrain. This correlation resulted

from experiments using air and water as test fluids over a wide range of parameters.


Table 3.1 Multiphase flow correlations

Correlation Notes

Vertical Upward Flow Duns & Ros Good in mist and bubble flow regions.

Angel-Welchon-Ross Applicable for high flow areas and annulus flow.

Recommended for high volume wells and low gas/oil ratios

Hagedorn & Brown Best available pressure drop correlation for vertical upward flow

Most accurate for angles of inclination greater than 70 degrees

Orkiszewski Result reliable for high gas/oil ratios


Aziz Generally slightly overpredicts pressure drop; other correlation tend to underpredict.

This fact can be used to bracket the solution.


Beggs & Brill Good for all angles of inclination.

Predicts the most consistent results for wide ranges of conditions.

Gray Specifically designed for condensate wells (high gas/oil ratios)

Recommended ranges: velocity< 15 m/s

Horizontal Flow

Lockhart-Martinelli Widely used in the chemical industry.

Applicable for annular and annular mist flow regimes if flow pattern is known a priori.

Do not use for large pipes

Generally overpredicts pressure drop

Eaton Do not use for diameters<50 mm [2 in]

Do not use for very high or very low liquid holdup.

Underpredicts holdup for Hl<0.1. Works well for 0.1<HL<0.35

Dukler Good for horizontal flow

Tends to underpredict pressure drop and holdup

Recommended by API for wet gas lines

Beggs&Brill Use the no-slip option for low holdup

Underpredicts holdup

Inclined Flow

Mukherjee-Brill Recommended for hilly terrain pipelines

New correlation based heavily on in situ flow pattern

Only available model that calculates flow patterns for all flow configurations and uses


Beggs and Brill model has been identified to be applicable in this study as it exhibits several

characteristics that set it apart from the other multiphase flow models:

a) Slippage between phases is taken into account

Due to the two different densities and viscosities involved in the flow, the lighter phase tends to

travel faster than the heavier one – termed as slippage. This leads to larger liquid hold-up in practice

than would be predicted by treating the mixture as a homogeneous one.

b) Flow pattern consideration

Depending on the velocity and composition of the mixture, the flow behavior changes considerably,

so that different flow patterns emerge. Depending upon the flow pattern established, the hold-up

and friction factor correlations are determined.

c) Flow angle consideration

This model deals with flows at angles other than those in the vertical upwards direction (Chang et al.,

2008).

A little different from another correlation, Beggs and Brill need early determination of flow regime to

calculate pressure drop. This part is used in this report for mechanistic models. These can be

classified as three types of regimes: segregated flows, in which the two phases are for the most part

separate; intermittent flows, in which gas and liquid are alternating; and distributive flows, in which

one phase is dispersed in the other phase.

Segregated flow is further classified as being stratified smooth, stratified wavy (ripple flow), or

annular. At higher gas rates, the interface becomes wavy, and stratified wavy flow results. Annular

flow occurs at high gas rates and relatively high liquid rates and consists of an annulus of liquid

coating the wall of the pipe and a central core of gas flow, with liquid droplets entrained in the gas.

The intermittent flow regimes are slug flow and plug (also called elongated bubble) flow. Slug flow

consists of large liquid slugs alternating with high-velocity bubbles of gas that fill almost the entire

pipe. In plug flow, large gas bubbles flow along the top of the pipe.

Distributive flow regimes described in the literature include bubble, mist, and froth flow.


Beggs & Brill determine the flow regime and liquid hold up as follow:

𝐿1 = 316𝐶𝐿0.302

𝐿2 = 0.0009252𝐶𝐿−2.4684

𝐿3 = 0.1𝐶𝐿−1.4516

𝐿4 = 0.52𝐶𝐿−6.738

L1, L2, L3, L4 are dimensionless numbers where can be determined if CL is known. Theoretically, Cl is

input volume fraction of liquid that defined as the ratio of liquid superficial velocity and mixture

velocity. The other dimensionless number that used to determine flow regime is Fraude number. It

may be written as

𝐹𝑟 = 𝑣2/𝑔𝐷

Based on above equations, the flow regimes are classified into four areas:

1. Segregated flow

𝐶𝐿 < 0.01 𝑎𝑛𝑑 𝐹𝑟 < 𝐿1

𝑜𝑟

𝐶𝐿 ≥ 0.01 𝑎𝑛𝑑 𝐹𝑟 < 𝐿2

2. Intermittent Flow

0.01 ≤ 𝐶𝐿 < 0.4 𝑎𝑛𝑑 𝐿3 < 𝐹𝑟 ≤ 𝐿1

𝑜𝑟

𝐶𝐿 ≥ 0.04 𝑎𝑛𝑑 𝐿3 < 𝐹𝑟 ≤ 𝐿4

3. Distributed Flow

𝐶𝐿 < 0.4 𝑎𝑛𝑑 𝐹𝑟 ≥ 𝐿1

𝑜𝑟

𝐶𝐿 ≥ 0.4 𝑎𝑛𝑑 𝐹𝑟 > 𝐿4

4. Transition Flow (not as an actual regime, only presents the existence of regime boundaries)

0.01 ≤ 𝐶𝐿 𝑎𝑛𝑑 𝐿2 < 𝐹𝑟 ≤ 𝐿3


Once the flow type has been determined then the liquid holdup can be calculated. Beggs and Brill

divided the liquid holdup calculation into two parts. First the liquid holdup for horizontal flow, EL(0),

is determined, and then the result is modified for inclined flow. EL(0) must be ≥ CL and therefore

when EL(0) is smaller than CL, EL(0) is assigned a value of CL. There is a separate calculation of liquid

holdup (EL(0)) for each flow type.

1. Segregated flow

𝐸𝐿 (0) =0.98𝐶𝐿

0.4846

𝐹𝑟0.0868

2. Intermittent Flow

𝐸𝐿(0) =0.845𝐶𝐿

0.5351

𝐹𝑟0.0173

3. Distributed Flow

𝐸𝐿 0 =1.065 𝐶𝐿

0.5824

𝐹𝑟0.0609

4. Transition Flow

𝐸𝐿 0 𝑡𝑟𝑎𝑛𝑠𝑖𝑡𝑖𝑜𝑛 = 𝐴𝐸𝐿 0 𝑠𝑒𝑔𝑟𝑒𝑔𝑎𝑡𝑒𝑑 + 𝐵𝐸𝐿 0 𝑖𝑛𝑡𝑒𝑟𝑚𝑖𝑡𝑡𝑒𝑛𝑡

Where

𝐴 =𝐿3 − 𝐹𝑟

𝐿3 − 𝐿3 𝑎𝑛𝑑 𝐵 = 1 − 𝐴

If all of the steps have been completed, then the liquid hold up can be determined. This information

will be used to find the actual liquid and gas velocity along the pipeline.

3.2 Sand Transportability in Pipe

Sand transportation in multiphase pipelines depends on several factors. Some of these factors are:

Flow regime, hold up, fluid properties (such as viscosity), inclination of the pipe in hilly terrains,

particle size distribution, relation between the superficial velocity of the liquid phase (Vsl) and the

superficial velocity of the gas phase (Vsg), pipeline diameter, friction factors, etc. For example, a

change of inclination implies a change in the flow pattern, and therefore, a change in the sand

transportation and sand behavior. The same happens for the viscosity. If the viscosity of the liquid

phase changes, the energy distribution of the gas and liquid phases is going to change, conditioning

the geometrical distribution of both phases in the pipeline, which means changing the flow pattern.


Angelsen in 1989 found that sand transport in horizontal pipelines has four main patterns depending

on the fluid flow rate (Salama, 1998). Basically, four flow regimes can be identified for the solid-liquid

slurry flow in horizontal pipe; those are saltation static bed (sand bed), saltation moving bed

(moving dunes), heterogeneous flow (scouring), and homogeneous flow (dispersed) (Chen, 1994).

Figure 3.7 Flow pattern in slurry flow

However, sand transportation in pipe concludes of more complex fluid composition: water, oil, and

gas. The flow regime determined before only told about the gas-liquid phase distribution, so that the

behavior and flow pattern map is a combination from gas-liquid and slurry flow.

Figure 3.8 Multiphase flow regimes consist of liquid, gas and solid

In annular flow, the sand particles can be transported in the water firm and in the gas core. In this

flow regime, since the velocities are high, the main concern is not the sand accumulation but the

erosion rate produced by the aggressive sand particles movement.


In low hold up wavy flow, the liquid is transported in a thin film on the bottom of the line, where the

sand concentration may be high, enhancing the creation of a settled sand bed.

In plug flow, gas pockets move along the top of the pipe having little effect upon the solid behavior.

As long as the gas velocity is increased, the gas pocket gets depth and the fluctuating velocities affect

the sand transportation similar to described at next in slug flow. Under this flow regime, for upwardly

inclined pipes, it can be seen that either the sand is transported in the plug body and in the film

region, or the sand particles settle in the gas plug zone (film region), and are only transported into

the plug body, or clusters of collided sand particles are formed, moving backwards in the gas pocket

(film region) and only moving forwards in the liquid plug body.

In slug flow, the sand particles behavior is complicated since the solids may be settled during the film

region and transported in the slug body; the sand movement is always intermittent and gas pockets

moving along the pipe have high effect upon the solid behavior. There can be a large diameter effect

as the depth of the film varies and shields the pipe bottom from the turbulence of the slug.

Moreover, the slug frequency is an important factor in sand transportation (Ruano, 2008).

Figure 3.9 Schematic sand behaviors in slug with low gas superficial velocity

Ruano in 2008 came with his observation about sand behavior in multiphase horizontal and near

horizontal (+5o) pipelines for his magister thesis. He tried to find the correlation between sand

behavior and flow pattern and vice versa. Flow regime analysis is conducted through the measured

hold up by capacitance instrumentation, for its comparison with the visual observation, and a

relation between flow pattern and sand transportation is pointed up. The real sand transportation in

multiphase oil pipelines is studied here by using water/air flows which contain different loads of


sand, by means of conducting sand settling experiments in the 4” (0.1 m) facility loop of Process and

System Engineering Department at Cranfield University, for a liquid superficial velocity interval from

0.55 to 0.15 m/s, for a gas superficial velocity range from 2.5 to 0.02m/s and for three sand

production rates: 0.04275, 0.57 and 1.425kg/m3.

It has been found that the sand transportation strongly depends upon the flow regime and, however,

upon each and every parameter which affects the flow pattern, such as inclination or, even, sand

production. It has been seen that the flow regime observed mainly depends upon the inclination,

showing big differences between horizontal and near horizontal (+5o). Therefore, the sand behavior

observed in horizontal pipe is completely different that in the upwardly inclined pipe.

First, Ruano identified the flow regime without any sand load to study how sand concentration

affects the flow pattern. For a certain value of Vsl, Vsg values are varied until all the regimes are

concluded. Then he replied those methods with different sand production rates; a recorded video

from the bottom of the pipe is conducted.

a. Smooth Stratified Flow

No obvious sand particles movements in liquid film zone

Sand settled in the bottom, sand dune formation in higher sand concentration

Figure 3.10 Sand behaviors in smooth stratified regime

Figure 3.11 Sand dune formation behaviors


b. Stratified-Wavy Flow

Formation of the big waves

Sand are seen to settle along the flow direction

Enough energy for sand to be transported

Figure 3.12 Sand behaviors in stratified-wavy regime

c. Plug Flow

High value of Vsl and low Vsg

Sand is not transported to barely move sliding in a plug body and settle in the film zone

Sand is encountered to be rolling or creeping

Figure 3.13 Sand behaviors in plug regime

d. Slug Flow

Facilitate sand transportation

As soon as the turbulent energy reaches the sand settled on the pipe well, the sand will be

carried and lifted into the slug body


Figure 3.14 Sand behaviors in slug regime

3.3 Critical Flow Velocity in Sand Transport

3.3.1 Horizontal Pipe

The critical flow velocity, Vc, is defined as the minimum velocity demarcating flows in which the

solids (sand particles) form a bed at the bottom of the pipe from fully suspended flows. It is also

referred to as the minimum-carrying or limiting-deposition velocity. Below this velocity, solids will

settle out and slurry flow cannot be maintained.

Below a critical velocity, sand will drop out of the carrier fluid and form a stable, stationary sand bed.

As the sand bed builds over time, the fluid above the bed is forced into a smaller cross-sectional area,

causing the fluid velocity to increase. When the velocity reaches a critical value, sand is transported

in a thin layer along the top of the sand bed. A steady-state is reached, such that the sand eroded

from the top of the bed is replaced by new sand production from upstream. At higher velocities, the

sand bed begins to break up into a series of slow-moving dunes, with sand particles transported from

the upstream to the downstream side of the dune. As the flow velocity increases still further, the

dunes break up entirely, and the sand forms a moving bed along the bottom of the pipe. At liquid

velocities above the critical sand-carrying velocity, the sand is fully entrained in the fluid phase, and

potentially entrained into the gas phase in multiphase flow (Danielson, 2007).

There are some theories from such as Durand-Condolios (1952) and Newitt et al. (1955) that

used to calculate Vc. Durand-Condolios classified the flow of slurries according to particle

size. Newitt suggested that it also depends on the density of material, the mean velocity, and

the pipe diameter. He also derived the evaluation of the energy losses due to flow of the fluid

and solid particles.


𝑉𝑐 = 𝐹𝐿 [2𝑔𝐷(𝑠 − 1)]0,5

Where D = pipe diameter; FL is a numerical constant depending on solids concentration and

particle size and is determined from Figure 3.15 ; (s-1) is equivalent to 𝜌𝑠−𝜌𝑤

𝜌𝑤 also = SGsoIids- 1.

Figure 3.15 FL value vs. particle diameter, concentration as parameter

Salama, M. M. (1998) combine the correlation developed by Oroskar and Turian (1980) with

predictions made by the DNV Carroline software for predict sand-settling in both single and

two-phase flows.

𝑉𝑚 = 𝑉𝑠𝐿

𝑉𝑚

0,53

𝑑0,17𝑣0,09 ∆𝜌

𝜌𝑓

0,55

𝐷0,47

Where Vm : mininum mixture flow velocity to avoid sand settling, m/s

VsL : ratio between liquid superficial velocity and mixture velocity

D : pipe diameter, m

∆𝜌 : density difference between sands and liquid, kg/m3

𝜌𝑓 : liquid density, kg/m3

𝑣 : kinematic viscosity, m2/s

3.3.2 Vertical Pipe

To determine sand settling velocity in sand transportability through vertical pipe, a model developed

by Chien (1994) can be used.

Sand Concen- tration


𝑉𝑚 = 120 𝜇𝑒

𝑑𝜌𝑓 1 + 0.0727 𝑑

𝜌𝑝

𝜌𝑓− 1

𝑑𝜌𝑓

𝜇𝑒

2

− 1

Where Vm : miminum mixture flow velocity to avoid sand settling, m/s

𝜇𝑒 : effective viscosity at various shear rates, Pa.s

d : particle diameter, m

𝜌𝑝 : particle density, kg/m3

𝜌𝑓 : liquid density, kg/m3

The above models do not account for the impact of condensate and added chemicals on sand

behavior and sand settling predictions. It is, however, expected that the above equation can lead to

conservative results because oil wetted sand should be expected to settle at a lower velocity than the

water wetted sand (Salama, 1998).

Analysis of Sand Transportability in Pipelines

29

CHAPTER IV

BEKAPAI OBSERVATION

4.1 Bekapai Production Network Configuration and Gas Lift


4.2 Pipeline Data and Fluid Volumetric Flow Rate

4.3 Particle Sieve Analysis

Figure 4.1 Particles sieve analysis

There are eight samples of sand particles that have been found in most area in Bekapai wells and

separators (V 100 and V 120) since 2006 until 2009. For this analysis, those particles are used to

identify the flow critical velocity in Bekapai pipelines.

0

5

10

15

20

25

30

35

40

45

50

% W

eigh

t

Diameter (mm)

Particle B

Particle C

Particle D

Particle E

Particle F

Particle G

Particle H

*Particle A has no sieve analysis

Pipeline P(bar) T (oC) Q Oil (STBD) Q Gas (MSCFD) Q Water (BWPD)

8 inch BK-BP1 10 60 1 960 68

6 inch BJ-BB 56 60 0 1302 1

12 inch BB-BP1 10 60 339 1608 2152

6 inch BF-BL 11 60 175 1712 1177

6 inch BH-BG 13 60 422 1239 478

12 inch BL-BA 10 60 5011 9540 4263

33 Analysis of Sand Transportability in Pipelines

CHAPTER V

BASIC CALCULATION FOR FLOW REGIME PREDICTION

(COMPARISON OF METHOD)

5.1 Empirical Correlation (Mandhane, Aziz et al. versus Beggs & Brill)

This calculation has been applied in Microsoft Excel 2007 for all pipelines in Bekapai (except 6” BE-

BA, 6” BL-BA, 6” BG-BL, 12” BG-BL because the flow are in single phase).

Objectives

a. Determine the flow regime for each pipeline

b. Comparative analysis between methods that used in determining flow regime

Variations

Variation used in this calculation is pipe geometry (horizontal or vertical).

Assumptions

a. Steady state flow

b. There is not an inter-phase mass or energy transfer

c. Temperature and pressure are constants along pipeline

Table 5.1 Average pressures and temperatures in Bekapai pipelines

Pipeline Pressure

(bar)

Average Temperature

(oC) 8 inch BK-BP1 10 60

6 inch BJ-BB 56 60

12 inch BB-BP1 10 60

6 inch BF-BL 11 60

6 inch BH-BG 13 60

12 inch BL-BA 10 60

5.2 OLGA versus Beggs & Brill

The calculation has been applied for some case studies in Microsoft Excel 2007 and OLGA. OLGA

was originally developed as a dynamic one dimensional modified two fluid model for two-phase

hydrocarbon flow in pipelines and pipeline networks, with processing equipment included. Later, a


water option was included which treats water as a separate liquid phase. OLGA was developed by

IFE in 1983 for the Norwegian State Oil Company, Statoil.

This comparison analysis is based from the main background to know how accurate the prediction

made by mechanistic model such OLGA compared with Beggs & Brill, which is really helpful to

solve kind of situations such as lack of appropriate data when a new well or pipeline is being

designed, “Industry Standard” correlations do not fit the available test data for some or all wells,

different correlations are used to match similar wells, or the same correlation yield incomparable

results in different application.

Objectives

The objective of this analysis is to compare flow regime, actual liquid and gas velocity, and

also holdup results between OLGA and Beggs & Brill model at Bekapai pipelines.

Variations

a. Pipe geometry (horizontal or vertical)

b. Flow mixture (gas-water or gas-oil)

Assumptions

a. Steady state flow

b. There is not an inter-phase mass or energy transfer

c. Temperature and pressure are constant along pipeline

First, the representative pipeline models for this analysis are created. In most cases, the wellhead

located under sea level and linked to the platform with subsea pipeline. Therefore, the geometry

of the pipeline includes horizontal line and riser in order to reach the production deck located

above sea level. The horizontal lengths follows real conditions in Bekapai, with riser are assumed

35 m height. Pipeline is divided into 100 horizontal and 10 vertical sections.

In real situation, the physical structure of pipe would follow the seabed contour. Moreover, the

flow regime performance is really sensitive to the inclination angle; defined as angle between

pipeline and the ground. In these following cases, inclined angles factor along the pipe are

ignored.


Table 5.2 Pipeline geometry data

Pipeline d (inch) Length (m) Wall thickness

(mm)

BB-BP 12 1660 9.52

BH-BG 6 1900 9.52

BF-BL 6 1000 9.52

BJ-BB 6 850 9.52

BK-BP 8 1900 9.52

BL-BA 6 1530 9.52

In order to determine the fluid regime in multiphase flow, the input and output data are

identified. Fluid data like composition and phase mixture are created in another program (PVT

SIM) because OLGA is not applicable to build its own fluid data source. For case studies applied,

the gas and oil composition can be seen below.

Table 5.3 Oil composition in OLGA

Components Mol fraction

Molecular weight 𝜌 (kg/m3)

C6 0.33 84 685 C7 0.12 96 722 C8 0.005 107 745 C9 0.04 121 764

C10 0.14 134 778 C11 0.16 147 789 C12 0.07 161 800 C13 0.005 175 811 C14 0.1 190 822 C15 0.03 206 832

Table 5.4 Gas composition in OLGA

Components Molecular

weight Yi C1 16.043 0.75

C2 30.07 0.21

C3 4.097 0.04


OLGA provides an option to activate “NO SLIP” indicator. If it is turned off, slip between phases is

calculated. In the other words, the actual liquid velocity between gas and liquid phase are become

different each other (like the real situation). The other option is “STEADYSTATE”, indicator used to

establish the steady state condition instead of transient.

Heat transfer is neglected for simplicity, and the wall temperature is assumed constant in 60oC.

The other parameters like pressure, GOR (gas oil ratio), GWR (gas water ratio), pipe diameter, and

standard gas flow rate follows data in Bekapai so that the model remains as close as possible to

the actual circumstances. Nevertheless, in order to analyze the effect of fluid properties through

flow regime, there are two variations in fluid flow applied: gas-water and gas-oil flow.

Table 5.5 Flow properties in each Bekapai pipeline

Pipeline Pressure (bar)

GWR (m3/m3)

GOR (scf/STB)

Gas std flow rate (Mscfd)

8 inch BK-BP1 10 277.82 720676.32 960

6 inch BJ-BB 56 5220.60 - 1302

12 inch BB-BP1 10 14.76 4742.69 1608

6 inch BF-BL 11 26.07 9781.97 1712

6 inch BH-BG 13 39.15 2953.69 1239

12 inch BL-BA 10 44.22 1903.88 9540


Figure 5.1 OLGA model view for gas-water case

It must be noticed that the output in OLGA are presented in two different ways, in TRENDPLOT

and PROFILEPLOT. TRENDPLOT shows the behavior of variables versus time in constant position

(called “section”). In the other hand, PROFILEPLOT shows the variable profile along the pipe in

certain range of time. So the results are not constant toward two variables, location and time.


CHAPTER VI

RESULTS AND DISCUSSION

According to the previous explanation about the theory and calculation used in this report, it was

a great challenge to make an analysis and summary about many parameters concluded in sand

transportability behavior. In the beginning, it was only to find the relation between flow regime

and sand settling, but the phenomena are not as simple as ever thought. Multiphase flow regime,

in fact, has not been really understood by researchers until now, since most of multiphase models

are based on only two phase, single liquid and gas. Many assumptions are made to generalize its

application in complex flow like in oil-gas industry, but the real problem are too many parameters

have been identified without sufficient correlation made.

In such a complex situation engineers avoid the mathematical difficulties by resorting to

experimental methods and develop "correlation" for engineering application. These correlations

are based on experimental results but, when the number of parameters that control the flow

pattern is large, than even this basic problem has its difficulties.

Figure 6.1 Factors affected sand transportation in pipeline

Sand Transportation in

Pipeline

(critical flow velocity and sand behavior)

Holdup

Fluid properties

(Vsl,Vsg,ᵨ,σ,µ)

Inclination

(θ)Particle

properties

(Dp,ᵨ)

Pipeline properties

(D,roughness)

Flow regime

Further

analyzed in

this report


To overcame this problem, this report only focused on the relationship between flow regime and

sand transportation, especially sand behavior along pipeline. The other parameters such as

inclination, hold up, etc. are discussed in general due to Bekapai flow as long as they have

connection with flow regime determination.

A comparative study has been chosen to determine multiphase flow regime in Bekapai pipelines,

due to various models that have been found so far. Inclination is the main issue in

experimental/empirical correlation because of only one map accepted for a certain inclination

angle. This is why the experimental correlation is not used in practice. There are several empirical

used in this analysis, such as Taitel & Dukler and Duns & Ros map which widely used today, but

they failed to describe flow regime because of the difficulty level applied in manual calculation

and unclear boundaries between each regime. The others are not really accurate and not

considered the slippage between phases.

Therefore, a different approach is introduced by another experimental correlation such as Duns &

Ros, Hagedorn & Brown, Orkiszewski, and Beggs & Brill. They are based on experiments and used

commonly to determine pressure drop in multiphase flow. From those ones, Beggs and Brill was

chosen in this analysis because some advantages like liquid hold up and slippage consideration,

relatively easy to use, and applicable in all inclination. But somehow it has some limitations in the

application that explained below:

1. It has an increasing error if GLR (gas liquid ratio) above 5,000.

2. The experimental investigation was conducted for tubing size between 1 and 1.5 in. Any

further increase in tubing size tends to result in an over prediction in the pressure loss.

3. The accuracy has been tested only for water-gas flow.

Hence, it can be concluded that all models that explained above are not recommended to use in a

different situation from which the experiment was done.

Then OLGA comes as one dimensional model of multiphase flow that capable to determine the

sand behavior included its flow regime. OLGA has many improvements and makes multiphase flow

analysis becoming easier to apply in industry. It can be used to make a prediction of oil-gas-flow

behavior along pipeline in steady state or transient condition, something that have never

investigated before.


A comparative study between these models is further investigated in this report. A block diagram

in the following page shows the general mechanism of flow regime determination.

Figure 6.2 Flow regime determination used in this analysis

Sometimes a very careful choice must be considered due to the percentage differences between

the results. Even when the value is large, it means nothing related to the validity because the main

focus of this analysis is “how closed”, not “how accurate”. In this chapter, the results of

calculation described in chapter V will be analyzed further. This chapter will be divided into two

sections: analysis of sand behavior and the flow critical velocity in vertical and horizontal pipe.

6.1 Analysis of Sand Behavior in Correlation with Flow Regime

Essentially, flow regime defined as the physical distribution of the phases in flow, especially the

distribution of energy. It has great effect to the sand transportation because the energy of flow

has able to move sand and avoid its settlement as long as the velocity of mixture is not achieve the

flow critical velocity. Every pattern occurred in flow has certain characteristics which depend on

the superficial velocity of liquid and gas.

Flow regime

Experimental Correlation

Horizontal Pipe

(Mandhane Map)

Vertical Pipe

(Aziz Map)

All inclinations

(Beggs &Brill)

Mechanistic Model

(all inclinations)

OLGA

Sand Behavior


It is not an easy task to predict the sand behavior from the flow regime and vice versa. Ruano

(2008) has analyzed this subject comprehensively in his thesis and found that in each regime

occurred, sand settling phenomena are possibly happened based on the rate of sand production

and flow velocity. According to this, the only information gathered is about the sand behavior, not

the sand settling condition. Thus, the main factor used to decide whether sand particles are

settled or not is still the flow critical velocity.

It is important to note that all flow regime model used here are able to explain only two until

three phases consist of single liquid-gas or gas-water-oil types. It will be described in the next

section.

6.1.1 Experimental Correlation (Mandhane, Aziz et al. versus Beggs & Brill)

The main reason to choose Beggs & Brill than the other map is its simplicity. In this model the

dimensionless number equations are used to substitute the boundaries between each flow

regime. Consequently, the flow regime map is not required anymore. In application, this method is

preferable although the whole calculation is more difficult than empirical correlation.

6.1.1.1 Horizontal Pipe

There are some maps that can be used to determine the flow pattern in horizontal pipe, but

Mandhane’s map is the one that widely used. This method is reported to give an overall accuracy

of about 70% when compared to the full data bank on which it is based (6000 flow pattern

observations).


Figure 6.3 Mandhane’s map for Bekapai pipelines

Blue node locations show the regime for each pipeline flow. This method is quite easy because it is

only based on superficial velocity of gas and liquid. As summary, the regime for each pipelines are

represented in table below.

Table 6.1 Flow regimes of Bekapai pipelines predicted using Mandhane’s map

Pipeline Gas superficial velocity

(ft/s) Gas-oil superficial velocity

(ft/s) Regime 8 inch BK-BP1 3.64 0.0134 Stratified

6 inch BJ-BB 1.41 0.0003 Stratified

12 inch BB-BP1 2.71 0.2126 Stratified

6 inch BF-BL 10.48 0.4616 Slug

6 inch BH-BG 6.39 0.3074 Stratified

12 inch BL-BA 16.09 0.7916 Slug


The Mandhane map given in Fig. 6.3 was developed for horizontal lines flowing air and water at

near atmospheric pressure. Inclinations in the range of 0.1-1.0 degrees can cause substantial

regime boundary movement. With an assumption that Bekapai pipelines are straight horizontal in

geometry (riser is not included), results above can be accepted. Besides, flow regime boundary

adjustment has been observed due to fluid pressure, pipe diameter, and surface tension in this

method. Because of three parameters above are assumed constant in these cases, the remaining

problem is how if these results are being compared with Beggs & Brill correlation.

Table 6.2 Horizontal flow regimes in Bekapai pipelines predicted using by Beggs & Brill correlation

(revised)

Pipeline Regime

8 inch BK-BP1 segregated

6 inch BJ-BB segregated

12 inch BB-BP1 segregated

6 inch BF-BL unknown

6 inch BH-BG unknown

12 inch BL-BA unknown

For 8”BK-BP1, 6”BJ-BB and 12”BB-BP1 pipelines, the flow regimes are matches with Mandhane so

it can be concluded that the flow regimes for those pipelines are segregated/stratified. Segregated

includes annular and stratified in Beggs & Brill’s terms, so explicitly it can be said that the regimes

are stratified, according to the Mandhane’s results. Beggs & Brill correlation, same with

Mandhane, is based on water-air flow in early investigated. For 6”BF-BL, 6”BH-BG and 12”BL-BA, it

does not show any information about the regime. One only reason is one or more requirements

used to determine flow regime are out of boundaries.

Nevertheless, the Beggs & Brill correlation originally based from Beggs & Brill map. When a

problem like “undefined regime” happened, it is better to ensure the results using this map. One

disadvantage of this model is the uncertainty of regime location related to the others. It does not

give any information about how close or how far the flow from the other regimes or relative


position between flows. This map below illustrated more clearly about some information that are

not provided by Beggs & Brill correlation.

Figure 6.4 Beggs & Brill map (1973) of Bekapai pipelines

Flow in 12”BL-BA, 6”BF-BL and 6” BH-BG are showed in transition and near transition regime.

Their positions are quite far from other three (6”BJ-BB, 8”BK-BP1 and 12”BB-BP1). However, these

results show different prediction from Beggs & Brill correlation that has been revised. With

assumption that there is nothing wrong in calculation, it should be corrected once more to find

another comparator.

Using the correlation which was published in 1973, Bekapai flow regime can be seen in Table 6.3.

The results are same with Beggs & Brill map in original line.


Table 6.3 Horizontal flow regime in Bekapai pipelines by Beggs & Brill correlation (1973)

Pipeline Regime

8 inch BK-BP1 Segregated

6 inch BJ-BB Segregated

12 inch BB-BP1 Segregated

6 inch BF-BL Segregated

6 inch BH-BG Segregated

12 inch BL-BA Segregated

Finally, all flow regimes in Bekapai pipelines are determined. These results seem reasonable

according to fluid velocity data. As known earlier, fluid velocity values (see Appendix A) between

BB-BP1, BF-BL, and BH-BG are not very different each other. Only 12”BL-BA has high rate of gas

(tenth times higher than 6”BH-BG; 269,501 m3/d). Hence, its gas velocity only approximately 5.15

m/s, a little bit larger than the others (0.43, 0.89, 1.12, 2.04, 3.34 m/s). Logically, it was not usual

for Beggs & Brill to fail predicting the flow regime in this range. In order to make things clear, for

all next cases the correlation from the origin paper will be used.

According to sand behavior in each pipeline, stratified flow is occurred in relatively low liquid and

gas velocity, so that the sand particles have consistent behavior in this regime. From wellheads,

sand concentration in liquid phase tends to be higher than gas phase because the gravity factor.

Liquid phase remains in the bottom and there is only little mass transfer between gas and liquid

phase. In this situation, whether sand particles will be carried away or settled along the pipe

depends on the liquid velocity. If the velocity is lower than the flow critical one, the sand will

settle and in higher concentration, they will form sand dunes. But, the other hand, sand will be

carried away by flow and there will be no sand accumulation in 8”BK-BP1, 6”BJ-BB, and 12”BB-

BP1.

Refer to Mandhane’s method, slug flow are occurred in 6”BF-BL and 12”BL-BA. Theoretically, slug

regime is avoided in field because it introduces a flow rate and pressure intermittency that may be

troublesome to process control, in example the flow can change from near 100% liquid to 100%

vapor. High liquid rates may fill separators causing process trips due to high level. High vapor


rates can lead to flaring or temporarily overload compressors causing trips due to compressor

instability and/or high pressure.

Nevertheless, the main focus in this section is the sand behavior in this regime which become

more complex because of slug phenomenon. Mixing zone that occurred is very effective to move

sand particles in the bottom. If pipe diameter is smaller, slug body can reach the bottom of pipe

and wipe the sand dunes into it. Slug frequency is the important factor for sand transportation in

this regime. In general, sand has much less possibility to settle in slug flow than stratified one.

6.1.1.2 Vertical Pipe/Upflow Risers

In vertical flow, gravity is a main force in the flow behavior. The less dense fluid will flow up faster

than the dense liquid and create swirling patterns much like a milk shake mixer. The dense liquid

will tend to flow downwards giving rise to what is defined as liquid holdup. For vertical flow, the

stratified flow regime cannot exist as there is no preferred direction for the liquid to settle. An

empirical flow regime map developed by Aziz et al. for vertical upward flow is shown in chapter 3.

The coordinates for this flow map are the same as for the Mandhane map in Fig. 6.3 except that

fluid property corrections are used.


Figure 6.5 Aziz et al. map of Bekapai pipelines

Until now, vertical map that can be used in various inclination angles does not exist. Aziz et al. has

made some correction in his method but in some situations it can make large error. Aggour et.al.

(1996) from Saudi Aramco proved that this method provides better predictions for lower GLR

values and higher water cuts (water volume fraction in oil/water mixture). In general, Aziz et al.

tends a good precision for larger tubing sizes and may be greatly improved by implementing

Orkiszewski’s flow pattern transition criteria.

In Bekapai cases, slug flow dominates all upflow risers, while Beggs & Brill provides different

predictions. According to Beggs & Brill, in vertical flow, the regimes are same as horizontal


because they follow same calculation rules. Thus, information about the results has been

explained in horizontal section.

Table 6.4 Flow regimes of vertical Bekapai pipelines based on Aziz and Beggs & Brill correlation

Pipeline

Regime

Aziz Beggs & Brill

8 inch BK-BP1 Slug Segregated

6 inch BJ-BB Slug Segregated

12 inch BB-BP1 Slug Segregated

6 inch BF-BL Slug Segregated

6 inch BH-BG Slug Segregated

12 inch BL-BA Slug Segregated

As can be seen from Table 5.8, Aziz et al. and Beggs & Brill methods are not in agreement each

other to determine vertical flow in Bekapai pipelines so there must be chosen between both of

them. It may be not the main focus in this report, but when there is something like this happen in

field; engineers are encouraged to find the best choice. If there is nothing wrong with calculation,

Beggs & Brill has found to be better than Aziz et al. in accuracy with average percentage error

about 6.72% (based on the present 414 data sets that cover a wide range of tubing size,

production rate, water cut, and GLR,[Aggour, 1996]). Aziz et al. only achieved 15.5 %

approximately. There are some cases like BK-BP1 and BJ-BB where GWR values are too high

compared with Aziz et al. effective range or the water cut are too low (BL-BA and BH-BG). More

details for GWR, GOR, and water cut values of each pipeline can be seen in Table 5.9.

Table 6.5 GWR, GOR, and water cut values of each Bekapai pipelines

Pipeline GWR (m3/m3)

GOR (scf/STB)

Water cut

8 inch BK-BP1 277.82 720676.32 0.98

6 inch BJ-BB 5220.60 - 1.00

12 inch BB-BP1 14.76 4742.69 0.86

6 inch BF-BL 26.07 9781.97 0.87

6 inch BH-BG 39.15 2935.69 0.53

12 inch BL-BA 44.22 1903.88 0.46


Granular materials like sand particles are known to show complex dynamical behavior, such as

convection, size segregation, bubbling, standing waves, etc. in vertical pipe. Sand is impossible to

settle under this condition, but much more effective to increase the pressure drop and erosion

rates, especially for annular (segregated) flow in Bekapai pipelines. Annular flow exists at high

superficial gas velocity and low superficial liquid velocity. The gas flows in the core region at high

velocity and the liquid flows as a thin annular film around inside the pipe wall and partially in the

form of liquid droplets entrained in the gas core. The droplet entrainment from a liquid film by a

streaming gas flow is of considerable importance because the same mechanism that causes liquid

droplets to be entrained can cause sand particles also to be entrained and contribute to the

erosion/corrosion process in BK-BP1, BJ-BB, and BB-BP1.

6.1.2 OLGA versus Begs & Brill

This section will explain further about flow regime in Bekapai pipelines by two different

categories: mechanistic models (OLGA) and experimental correlation (Beggs & Brill). Beggs & Brill

has been proved as the most accurate correlation for pressure drop prediction (Aggour et. al.,

1996), while OLGA has known widely as multiphase flow simulator used in many fields. A little

different with previous section, the fluid actual velocity and liquid holdup will be discussed since

they have close relation with flow regime determination. Sand behavior in each pipeline will not

be explained related to the objectives of this analysis.

In fact, flow regime detected in pipe at a certain time and location should be different with

another situation. So far, experimental correlation and Beggs & Brill have not yet considered

effect of two dimensional parameters, time period and location. For example, sand bed formation

for long period can cause smaller cross-sectional area for oil-gas flow and increase the flow

velocity. It could change the flow pattern actually. Along pipeline, there will be a different

concentration of sand, so that the flow regimes in pipe section are vary according to the location.

OLGA seems to pay attention more to those parameters. Besides, it has successfully generalized

the flow pattern of horizontal and vertical flow into only four: stratified (1), annular (2), slug (3),

and dispersed (4). BB has three different patterns (segregated, intermittent, and distributed) that

also used for all inclined angles. The most difficult problem to solve in this case is how to compare


such flow regime, holdup, and fluid velocity profiles which strongly depend on period and physical

parameters in OLGA (dynamic model) with Beggs & Brill correlation.

To overcome this problem, there are three sections which become the main concern of this

analysis: one in horizontal section (50th section), in the bottom of riser (101th section), and in the

pipe outlet (110th section). The parameters observed are the pressure, liquid volumetric flow rate,

flow regime, hold up, liquid and gas actual velocity. The profiles will be investigated in 48 hours for

every 10 minutes. Start from these, the comparative study with Beggs & Brill can be studied

further, especially to predict the sand behavior.

In order to simplify the cases, water-oil-gas flow is divided into two types of flow: oil-gas and

water-gas flow. Two phases flow phenomenon has been studied in many papers from various

fields. In Bekapai, the flow is more complex; three phases flow (gas-oil-water) include solid or

other deposits. This time, these are purely comparative studies between mechanistic model with

experimental correlation with an assumption if there are only two phases exist (e.g. gas-oil or gas-

water case). GOR values still follows the real condition in Bekapai.

Liquid holdup is that fraction of a pipe segment which is occupied by liquid. An estimation of liquid

holdup is vital to analyzing two-phase flow systems because the liquid holdup not only determines

the cross sectional area available for gas flow, but also determines the liquid inventory in the line.

This is also associated with sand behavior and estimation of slug size. It is important to be noticed

that liquid holdup is not the same as inlet liquid content in this case. If both values are similar, the

method relies on the assumption that the gas and liquid travel through the pipe at the same

velocity (no slip occurred between the phase). Beggs & Brill has considered the slippage in its

correlation, while OLGA has provided alternatives to facilitate the requirements.


6.1.2.1 Oil-Gas Flow

6.1.2.1.1 8” BK-BP1

Figure 6.6 Flow regime, holdup, and fluid velocity at 50th section in 8” BK-BP1 (oil-gas flow)

Figure 6.7 Flow regime, holdup, and fluid velocity at riser bottom in BK-BP1 (oil-gas flow)


Figure 6.8 Flow regime, holdup, and fluid velocity at pipe outlet in 8” BK-BP1 (oil-gas flow)

a. 50th Section (Horizontal Line) In horizontal line, OLGA illustrated the flow regime clearly in stratified flow. The pressure

fluctuates (increases for approximately 0.5 bar) because there is bulk of oil that accumulate in

riser bottom (effect of 90o elbow). It makes the liquid holdup increasing until close to 1,0. Then

the pressure becomes very high to carry away the oil. The holdup range is between 0.07 and 0.95.

Actual liquid and gas velocity are unstable according to slug formation.

b. 101th Section (Riser Bottom) Flow regimes are varies between stratified, annular, slug, and even dispersed in riser bottom. This

is the first section of vertical pipe, and oil as heavy liquid become easier to accumulate here

before it flows back. At first, the liquid velocity is too small to carry away oil through vertical

section (<0.10 m/s). For a certain period (±50,000 s), gas is forced to flow in smaller cross

sectional area until the way is totally blocked by oil (holdup values are between 0,0 until 1,0). Gas

actual velocity reaches the highest value at this time. It can achieve 5.5 m/s at highest peak.

c. 110th Section (Pipe Outlet) Annular flow occurs within 48 hours at outlet pipe, except at T = 47,467 s and 132,670 s when it

becomes slug. Slug is caused by phenomenon that has been described early. When oil blockage


occurs, gas velocity in this section decreases drastically and reaches its minimum value. Then the

pressure along pipe becomes very high to anticipate the trapped gas. As consequences, gas and

liquid velocity increases sharply before it starts to move back to lower values because pressure’s

falling down.

Table 6.6 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oil-gas flow (8” BK-BP1)

50th section (horizontal line)

Beggs & Brill (horizontal)

101th section (riser bottom)

110th section (pipe outlet)

Beggs & Brill (vertical)

Flow Regime

Stratified

Segregated

Stratified, annular, slug,

dispersed

Mostly annular, slug,

dispersed

Segregated

Holdup 0.070-0.078 (fluctuating)

0.01 0-1 (slug) 0-0.15 (slug) 0.02

Actual Liquid Velocity

Too low (fluctuating,

closer to zero)

0.01 m/s

Too low (assumed

zero), except in slug regime (reach 1.5 m/s

0-(-1.3) m/s

0 m/s

Actual Gas Velocity

0.75-2.25 m/s (fluctuating)

1.12 m/s

(-3.6)-5.5 m/s (back flow)

-1.3-(4) m/s (back flow)

1.13 m/s

Since OLGA has dynamic value, it is quite difficult to compare the results with Beggs & Brill.

Moreover, some results are too low and fluctuating because oil accumulation in horizontal line. Oil

accumulation is possibly occurred because there is not enough pressure drop and pipe oversize. In

the other hand, OLGA and Beggs & Brill still show similar results in flow regime determination and

most of Beggs & Brill predictions have been included in OLGA results.


6.1.2.1.2 12” BB-BP1

Figure 6.9 Flow regime, holdup, and fluid velocity at 50th section in 12” BB-BP1 (oil-gas flow)

Figure 6.10 Flow regime, holdup, and fluid velocity at riser bottom in 12”BB-BP1 (oil-gas flow)


Figure 6.11 Flow regime, holdup, and fluid velocity at pipe outlet in 12”BB-BP1 (oil-gas flow) a. 50th Section (Horizontal Line) It can be seen in Figure 6.8 that stratified regime is occurred in 50th section although the velocity

of gas are varies from -0.79 until 2.25 m/s. Oil accumulation is still possible to make the liquid

holdup reach value of 0.5. It also causes actual velocity of gas to fluctuate and reach its highest

level.

b. 101th Section (Riser Bottom) There is such a complex phenomenon occurred in BB-BP1 since it has slug regime. The first slug-

dispersed is identified in 22,203 s, caused by accumulation of oil in the bottom of riser. The holdup

in this section increases drastically from 0.19 until 0.723 before it becomes slug. The pressure also

rises up until 11.94 bar and becomes fluctuating. Oil is carried away after 26,400 s approximately.

Then the pressure is stable at 11.04 bar before the next slug regime occurs.

Flow regimes change between stratified, slug, dispersed, and annular. Liquid velocity fluctuates

when flow become slug and dispersed. Period of each flow regime depends on values of liquid and

gas velocity. The negative value of liquid velocity causes the dispersed regime while gas velocity is

high. There is situation when gas velocity reach 8 m/s and flow back at 4 m/s. Gas and oil create a

serious turbulence that affect the outlet product of pipe.


c. 110th Section (Pipe Outlet)

In general, outlet section has annular regime, but there is one time when it becomes slug and

dispersed. It is very important to be noticed that this kind of situation should be avoided in real

situation. High pressure and high volumetric flow of oil should cause some problems of stability

and separator performance. For both regimes, liquid and gas velocity are very high (4.05 and 3.65

m/s).

Table 6.7 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oil gas flow(12” BB-BP1)






Flow Regime

Stratified

Segregated

Stratified, annular, slug,

dispersed

Mostly annular, slug,

dispersed

Segregated


0.12 0-1 (slug) 0-0.25 (slug) 0. 15


-0.79-2.25 m/s (fluctuating,

closer to zero)

0.08 m/s

Too low (assumed

zero), except in slug regime (reach 1.5 m/s

0-(-1.5) m/s

0.14 m/s

Actual Gas Velocity

0.8-2.9 m/s (fluctuating)

0.93 m/s

(-4)-8 m/s (back flow)

-1.3-2.2 m/s (back flow)

2.18 m/s







6.1.2.1.3 6” BF-BL

Figure 6.12 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BF-BL (oil-gas flow)

Figure 6.13 Flow regime, holdup, and fluid velocity at riser bottom in 6” BF-BL (oil-gas flow)


Figure 6.14 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BF-BL (oil-gas flow)

a. 50th Section (Horizontal Line)

Interaction between gas and oil phase occur in horizontal section. Although OLGA predict the flow

regime is stratified, but it is not impossible for both phase to collide each other. This is supported

by backflow of oil in the riser and horizontal section. Its velocity is quite high (>0.17 m/s). At the

situation, gas also experiences flow back as consequences of liquid turbulences. In the other hand,

1,177 bpd of oil keep moving into the pipeline and make horizontal liquid holdup increases slowly

from 0.17 until 0.18. Within 48 hours there is only a little amount of liquid can reach pipe outlet

(liquid velocity = 0.001 m/s). It comes from water droplets carried by gas phase along the riser.

b. 101th and 110th Section (Riser)

At the very beginning (T = 0 s), the pressure is large enough to fill the riser with oil (holdup = 1).

The phenomena are actually same with BH-BG and BL-BA. Then liquid holdup will reach the

average value lower than 0.1. The liquid amount becomes very small in the riser.


Table 6.8 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oil-gas flow (6” BF-BL)






Flow Regime

Stratified

Segregated

Annular

Annular

Segregated


0.06 0 0 0. 1



closer to zero)

0.28 m/s

Negative (back flow)

0.001 m/s 0.18 m/s

Actual Gas Velocity

Too low (fluctuating,closer

to zero)

3.63 m/s

0.002 m/s

0.001 m/s

3.78 m/s







6.1.2.1.4 6” BH-BG

Figure 6.15 Flow regime, holdup, and fluid velocity at 50th section in 6” BH-BG (oil-gas flow)

Figure 6.16 Flow regime, holdup, and fluid velocity at riser bottom in 6” BH-BG (oil-gas flow)


Figure 6.17 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BH-BG (oil-gas flow)


Outlet pressure in the outlet of 6”BH-BG is assumed constant at 13 bar. OLGA simulates the

pressure inlet is 15.22 bar and create very high holdup in riser (1.0) and horizontal section (0.54).

The actual velocities of gas and liquid in T= 0 s are very low (close to zero). Then the horizontal

pressure fall down to 13.49 bar, makes oil back flowing down the riser. The holdup in the 50th

section becomes 0.4.

Turbulences occurred in horizontal section, creates little waves with constant frequency. As

consequences, liquid and gas velocities are unstable (their values changes between positive and

negative values). It means gas flow is also influenced by the oil back flow.


In general, the velocities of mixture are very low (0.00-0.02 m/s) because the pressure drop

between both of horizontal nodes are not high (only 0.01 bar). Oil is trapped in the horizontal

section and gas still moves forward very slowly because of turbulence. In the riser bottom, oil is

identified to flow back and has negative velocity. As consequences, there is only a little gas flow at

the outlet section. There is no oil remaining.


Flow regimes are identified as stratified at 50th section and annular at the riser. Based on the

explanation above, those results are the most suitable to describe the phenomena.

Table 6.9 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill (6” BH-BG)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup ±0.4, fluctuating 0.15 0 0 0.21



closer to zero)

0.28 m/s



closer to zero) 0.2 m/s

Actual Gas Velocity


to zero)

2.01 m/s

Too low, close to zero


2.16 m/s







6.1.2.1.5 12” BL-BA

Figure 6.18 Flow regime, holdup, and fluid velocity at 50th section in 12” BL-BA (oil-gas flow)

Figure 6.19 Flow regime, holdup, and fluid velocity at riser bottom in BL-BA (oil-gas flow)


Figure 6.20 Flow regime, holdup, and fluid velocity at pipe outlet in 12”BL-BA (oil-gas flow)

At time (T) = 0 s, 12”BL-BA pipeline has already fulfilled by water with horizontal and vertical hold

up for 0.83 and 1. The pressure is about 12.14 bar in the inlet before it falls down to 10.13 bar

within 160 s. Thus, oil will flow back into the horizontal section from riser and fulfills the area of

pipe. This phenomenon create negative value of liquid actual velocity (-0.06 m/s) and also for gas.

Hence, gas and oil is a little bit different. Oil will stay in horizontal pipe, make waves with constant

frequency between two directions of flow while gas will continue to flow through the pipeline and

the riser with average velocity 0.003 m/s.


Flow regime in horizontal pipe is stratified since most of oil are trapped, only a little amount of it

is carried away by gas so that in the outlet pipe there always be liquid with actual velocity for

0.002 m/s (same with gas). Besides, the liquid holdup in the outlet always zero, different with the

horizontal section which has liquid holdup approximately for 0.33. This value is increasing through

time until reach 0.39 within 48 hours.


Annular regimes are occurred in outlet and in the bottom of the riser. The phenomenon is simply

understood as follows: oil is flowing back through pipe wall while gas which carry little oil droplets


is flowing to the outlet. It is the reason why liquid velocities in the bottom of riser are always

negative.

Table 6.10 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oil-gas flow(12” BL-BA)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup ±0.35-0.4 (fluctuating)

0.12

0 0 0.19



closer to zero)

0.92 m/s


-2.5 -0 m/s (back flow)

0.68 m/s

Actual Gas Velocity


to zero)

5.8 m/s



6.08 m/s






6.1.2.2 Water-Gas Flow

Water and gas mixture has different characteristics (density, viscosity, and surface tension) from

oil-gas in pipe flow. Basically, they will affect the sand behavior and flow pattern, such as viscosity

that related to the energy distribution and fluid velocity. Hence, the main concern in this analysis

is still comparative study between OLGA and Beggs & Brill, whether they still fit each other or not

in water-gas horizontal flow.


6.1.2.2.1 12” BL-BA

Figure 6.21 Flow regime, holdup, and fluid velocity at 50th section in 12” BL-BA (water-gas flow)

Figure 6.22 Flow regime, holdup, and fluid velocity at riser bottom in 12” BL-BA (water-gas flow)


Figure 6.23 Flow regime, holdup, and fluid velocity at pipe outlet in BL-BA (water-gas flow)

Water content in BL-BA is higher than any other Bekapai pipelines which are studied in this report.

Moreover, gas volumetric flow is also very high (9,540 bpd). Liquid holdups in horizontal and

vertical line are about 0.27 and 0.75. Then the values become low because the pressure decreases

until 10.03 bar from 12.71 bar. Water in the riser falls down and creates turbulences with gas

phase which flows in the opposite direction.


In stratified regime (horizontal line), water and gas are continuous phase. Since the liquid velocity

is only 0.02 m/s, the liquid holdup increases slowly from 0.26 until 0.3 within 48 hours. It means

gas can always reach the top of the riser with average velocity of 0.01 m/s.


The pressure drop now is only about 0.006 bar between 50th section and bottom riser. In this

situation gas and liquid velocities are fluctuating. The gas velocity is relatively too low to move

water from horizontal area. Finally, liquid holdup in the riser is zero, but there is still little water

droplets that come out from pipe. Liquid and gas velocity in this section are same (±0.01 m/s).


Table 6.11 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in water-gas flow(12” BL-BA)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup ±0.35-0.4 (fluctuating)

0.12 m/s

0 0.01 1.443


Too low, fluctuating,back

flow

0.92 m/s

0.015 m/s fluctuating


0.68 m/s

Actual Gas Velocity


to zero)

5.58 m/s

-0.00448, (fluctuating)

0.015

0.01 m/s

From Table 6.6, it can be concluded that Beggs & Brill has the same flow regime with OLGA

although the other values are not match. The possible reasons to explain its difference includes:

the geometry of pipe, source location, and different principal between OLGA and Beggs & Brill to

determine holdup and velocity.

6.1.2.2.2 6” BH-BG

Figure 6.24 Flow regime, holdup, and fluid velocity at 50th section in 6” BH-BG (water-gas flow)


Figure 6.25 Flow regime, holdup, and fluid velocity at riser bottom in 6” BH-BG (water-gas flow)

Figure 6.26 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BH-BG (water-gas flow)


The phenomenon is exactly the same with 12”BL-BA. The flow at 50th section is predicted as

stratified flow, while the other two sections are annular. Holdup at T = 0 s in horizontal and riser

are 0.29 and 0.95. Before water can flow through the pipe outlet, the pressure moves from 16.56


bar to 13.03 bar. It makes lower pressure drop and lower fluid velocity (only 0.003 m/s average for

gas and zero for liquid).


At the bottom of riser, water velocity is in negative value, means that water still flows back. In this

section, holdup is zero, same with pipe outlet. Instead of water, gas has positive value in velocity

even the velocity is very low (0.001 m/s). Gas and water has the same velocity at 0.001 m/s at the

outlet.

Table 6.11 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in

water-gas flow(6” BH-BG)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup 0

0.16

0 0.01 0.23


Too low (close to zero)

0.3 m/s Negative (back

flow)


0.22 m/s

Actual Gas Velocity

Too low (close to zero,

fluctuating)

2.03 m/s

-0.00448 ,/s (fluctuating)

0.015

2.19 m/s






6.1.2.2.3 6” BF-BL

Figure 6.27 Flow regime, holdup, and fluid velocity at 50th section in 6” BF-BL (water-gas flow)

Figure 6.28 Flow regime, holdup, and fluid velocity at riser bottom in 6” BF-BL (water-gas flow)


Figure 6.29 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BF-BL (water-gas flow)


The phenomenon is exactly the same with 12” BL-BA. The flow at 50th section is predicted as

stratified flow, while the other two sections are annular. Holdup at T = 0 s in horizontal and riser

are 0.36 and 0.95. Before water can flow through the pipe outlet, the pressure moves from 14.41

bar to 11.03 bar. It makes pressure drop is low and so does the fluid velocity (only 0.002 m/s

average for gas and zero for liquid).


At the bottom of riser, water velocity is in negative value, means that water still flows back. In this

section, holdup is zero, same with pipe outlet. Instead of water, gas has positive value in velocity

even the velocity is very low (0.002 m/s). Gas and water has the same velocity at 0.002 m/s at the

outlet.



water-gas flow (6” BF-BL)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup 0.36 0.16 m/s 0 0 0.23



flow

0.77 m/s


flow


flow 0.54 m/s

Actual Gas Velocity

0.004 m/s (fluctuating, back flow)

4.04 m/s


flow

Too low, fluctuating,b

ack flow 4.4 m/s





6.1.2.2.4 6” BJ-BB

Figure 6.30 Flow regime, holdup, and fluid velocity at 50th section in 6” BJ-BB (water-gas flow)


Figure 6.31 Flow regime, holdup, and fluid velocity at riser bottom in 6” BJ-BB (water-gas flow)

Figure 6.32 Flow regime, holdup, and fluid velocity at pipe outlet in 6” BJ-BB (water-gas flow)

In OLGA, 6”BJ-BB simulation was developed at lower value than the real liquid flow rate in field

(0.79 stb/d). Assuming that OLGA model is an exact representation of the flow data set, the

phenomenon is exactly similar with the others which have been described (see Figure 6.29-6.31).

Considering the value of liquid flow rate that is very low, the flow can be assumed only composed

by gas phase, so that the behaviour is closed to single flow.


As can be seen from Figure 6.29, the regime is stratified in horizontal line. Gas velocity in this

situation is very low, only for 0.0014 m/s while the liquid flow rate can be negligible. In the outlet

section, the gas volumetric flow rate can be represented by a value of 0.006 m3/s, since the

velocity of gas is very low (0.0002 m/s). Annular regime is occurred along the riser with liquid

holdup is about zero. Water is likely to be coalesced in gas phase and carried into the pipe outlet.


water-gas flow (6” BJ-BB)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup 0.17 0.02 m/s 0 0 0.03


Too low, fluctuating, back

flow

0.01 m/s

Negative, back flow

Too low, fluctuating, back flow

0 m/s

Actual Gas Velocity


0.57 m/s



0.58 m/s


although the other values are not match. The holdup values obtained from Beggs & Brill are not as

low as OLGA, moreover, the actual gas velocity are rather too high. The possible reasons to explain

its difference includes: the geometry of pipe, source location, and different principal between

OLGA and Beggs & Brill to determine holdup and velocity.


6.1.2.2.5 8” BK-BP1

Figure 6.33 Flow regime, holdup, and fluid velocity at 50th section in 8” BK-BP1 (water-gas flow)

Figure 6.34 Flow regime, holdup, and fluid velocity at riser bottom in 8” BK-BP1 (water-gas flow)


Figure 6.35 Flow regime, holdup, and fluid velocity at pipe outlet in 8” BK-BP1 (water-gas flow)

In addition to compare results that obtained from OLGA with Beggs & Brill, there are three

sections which are observed further. The previous pipelines show significance values change

through time. Most of them are unstable due to the involvement of various factors and effects of

pipe geometry. Results of BK-BP1 have totally different characteristics based OLGA simulation.

Holdup, liquid velocity and gas velocity have reached steady state within 14 minutes. Then their

values are constant along 48 hours. The regimes are observed as annular in the outlet pipe and

stratified in riser bottom and horizontal section. The results can be seen in Table 6.15.



water-gas flow(8” BK-BP1)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Stratified

Annular

Segregated

Holdup 0.093 0.06 0.025 0.019 0.1


0.06 m/s 0.06 m/s 0.06 m/s Back flow 0.04 m/s

Actual Gas Velocity

0.99 m/s 1.19 m/s

0.99 m/s 0.93 m/s 1.23 m/s

This time the comparison results show promising progress, since the flow regime and liquid

velocity for horizontal are similar. Holdup by Beggs & Brill seems too high for vertical flow

according to OLGA, but for horizontal the result is still allowable. Besides, gas velocities are quite

different between both of them. For pipe outlet, liquid velocity is negative, means the water is

move downhill through pipe wall.

6.1.2.2.6 12” BB-BP1

Figure 6.36 Flow regime, holdup, and fluid velocity at 50th section in 12” BB-BP1 (water-gas flow)


Figure 6.37 Flow regime, holdup, and fluid velocity at riser bottom in 12” BB-BP1 (water-gas flow)

Figure 6.38 Flow regime, holdup, and fluid velocity at pipe outlet in 12” BB-BP1 (water-gas flow)

Slug and dispersed regimes dominates this pipeline flow until 48 hours. It is difficult to obtain any

information about liquid holdup and fluid velocity since the values are really inconsistent. The

pressure varies between 10.4-11.6 bar. Liquid holdup for horizontal section fluctuates at average

values of 0.4. The worst situation occurred in the bottom riser which has zero holdup until 1.0. It

means water has fulfilled the horizontal pipe, hindered the gas path. As consequences, the


pressure will arise drastically to escape gas from water blockage. The maximum value of liquid and

gas velocity in this section are 5.8 and 1.7 m/s respectively. The flow regime changes almost every

2 hours.

In general, the outlet section shows the same trend with riser bottom. In this section, the liquid

and gas velocity are high enough to create some turbulences (see Figure 6.36 and 6.37). Holdup

increases sharply when the flow regime turns into slug or dispersed.


water-gas flow(12” BB-BP1)


Beggs & Brill

(horizontal)



Beggs & Brill

(vertical)

Flow Regime

Stratified

Segregated

Annular

Annular

Segregated

Holdup 0.093 0.27 0.025 0.02 0.34


0.06 m/s 0.21 m/s 0.06 m/s -0.28 m/s (back

flow)

0.17 m/s

Actual Gas Velocity

0.99 m/s 1.16 m/s 0.99 m/s 0.93 m/s 1.28 m/s

Both of them shows totally different for all variables observed. This may be accepted due to some

reasons that have been explained above.

6.1.3 Main Finding

6.1.3.1 Experimental Correlation (Mandhane, Aziz et al. versus Beggs & Brill)

Except OLGA, other model like Beggs & Brill and flow regime map depend strongly on the origin

fluid and situation which the experiment defined. Many correction have been built to generalize

such models, however, they were all developed and tested under limiting operating conditions.

This is a very challenging subject because gas-liquid-solid flows are usually very complex, due to

the large number of variables involved in the transport processes, and typically poorly understood

interaction between the variables. Many of the earliest investigations of this flow focused only on

the settling tendency of solid particles without enough consideration about the sand behavior.


Based on literature study and calculation that have been analyzed, Beggs & Brill is better than

Mandhane and Aziz et al. to predict the flow regime in Bekapai pipelines. According to this, all of

All Bekapai pipelines consist of stratified flow in horizontal sections. This regime type is common

in oil-gas transportation system in pipe. With gas and liquid velocities which are low and

separated phase existence between liquid and gas, favorable condition for sand settling is likely

created. Hence, in vertical pipe, slug and segregated flow regime are predicted. Stratified is not

possibly occurred in vertical flow so that annular is estimated to occur in this position. Gas is the

continuous phase in annular regime so that gas behaviour will mostly affect the sand

transportation in Bekapai pipelines.

6.1.3.2 OLGA versus Beggs & Brill

Comparative study between OLGA and Beggs & Brill has been done to learn the performance of

both methods to determine multiphase flow properties (flow regime, liquid holdup, and fluid

velocity) if they are applied in real cases in field. The flow regime results are found match in 6”BF-

BL, 6”BH-BG, 12”BL-BA, and 6”BJ-BB. In 8”BK-BP1 and 12”BB-BP1 pipelines, the similarity between

OLGA and Beggs & Brill only exist in horizontal line since more complicated regime are shown by

OLGA at riser bottom and pipe outlet. It is also proven that OLGA and Beggs & Brill prediction are

found identical for flow regime determination either in oil-gas or water-gas flow.

Liquid holdup and fluid actual velocity that obtained from OLGA simulation are rather complex

and dynamic. It makes own difficulties to compare them with Beggs & Brill. Thus, both results are

not closed each other for all pipelines in Bekapai. The main reason lies in their different views of

model application. Beggs & Brill indeed has different correlation for each inclination angle, but it

does not consider the effect of inclination change over flow pattern itself. By the division of pipe

into smaller segments including time consideration, OLGA is one step ahead from Beggs & Brill in

this case.

Slug is found in 12” BB-BP1 and 8” BK-BP1 (gas-oil flow). In the other hand, 6” BF-BL, 6”BH-BG, 12”

BL-BA and 6” BJ-BB do not experience slug, but fluid velocity in their horizontal section are

unstable (turn into back flow within seconds). This turbulence or wave will occur and make sand

settling easier because flow do not tends go forward smoothly.


Many factors or parameters that affect flow regime are included here, but for some reasons they

are not described further in this report. Sand behavior in this section is not completely explained

because the critical velocity to avoid sand settling has not been discussed.

6.2 Analysis of Sand Settling Condition

Sand settling is an issue of concern at low velocities of oil-gas mixture along pipeline. Together

with sand erosion and sand monitoring, sand settling is important elements of any effective sand

production management strategy. Many literatures that reported about sand settling describe the

phenomena as two phase flow of solid-liquid like Newitt, Stuhmiller, and Nunziato. Studies about

oil-gas-water phase flow with sand existences are very rare; most of them used experimental

investigation to determine critical flow velocity to avoid sand settling. D.G. Thomas (1961) defined

the critical velocity as the mean stream velocity required to prevent the accumulation of a layer or

either stationary or sliding particles on the bottom of a horizontal conduit.

Salama (1989) reported his investigation about sand production management which define sand

settling as the transition between scouring and moving dunes (i.e. sand is on the bottom of the

pipe but moving along the pipe). The flow velocity at this condition would be lower than the

velocity to disperse the sand, but high enough to transport the sand through the pipeline. In this

analysis, critical flow velocity definition in horizontal pipe is based on Salama. Comparative study

between Salama and Bekapai cases can be seen in Table 6.14. Salama was chosen because his

investigation is most closely approximates the condition of Bekapai.

Table 6.17 Salama versus Bekapai case

Investigation by Salama (1989)

Bekapai case

Sand particle size 100, 280, and 500𝜇m 140, 180, 240, 235, 240, 256, 264, and 1000 𝜇m

Pipe diameter 4 in 6, 8, 12 in

Media Water, gas (CO2, N2, air), oil, inhibitors, sand

Water, oil, gas, sand

Water cut 1%, 10%, 50%, and 100% 46%, 53%, 86%, 87%, 98%, and 100%

Pressures 4 and 8 bara 11, 12, 14 , 57 bara

Temperature Ambient Wall (60oC)


Table 6.17 Salama versus Bekapai case (continued)

Liquid flow rate 0.03, 0.1, 0.2, 0.3, 0.4 m/s 0, 0.06, 0.09, 0.14, 0.24 m/s

Gas flow rate Varied during tests 0.43, 0.83, 0.1.11, 1.95, 4.91 m/s

Same with flow regime experimental correlation, Salama equation cannot be used in vertical flow.

Sand behavior observed in horizontal flow is completely different that in vertical pipe. Chien

(1994) developed new correlation to predict the settling velocity of irregularly shaped particles in

Newtonian and non-Newtonian fluid for all types of slip regimes. This model is recommended for

using in vertical case.

Even there is a relationship between flow regime and sand transportation, as stated earlier; it

does not mean that it will affect sand settling condition directly. Salama (2000) and Newitt (1962)

have already reported about four flow patterns defined in slurry flow, however, they are different

with flow patterns for multiphase flow as showed in previous section. Ruano (2008) came with his

thesis to understand the sand behavior in multiphase flow in horizontal and near horizontal. He

analyzed explicitly about flow regime relation with flow critical velocity under various sand

production rates. The results indicate that there are always possible for sand to settle in each

regime, depends on fluid velocity and rates of sand production.

Therefore, “sand settling” subject in correlation with flow regime can only be investigated by

experiment until now. Hence, there are some other factors that also affect sand settling

phenomena. They will be analyzed further in this section.

6.2.1 Horizontal Pipe

This is easier to observe sand settling in horizontal line (inclination angle = 0o) than vertical one

(inclination angle = 90o). There are many papers reported about the phenomena although only

few of them fit with multiphase flow. Quantitatively, flow critical velocity in Bekapai pipeline can

be seen in table below.


Table 6.18 Flow critical velocity in several Bekapai pipelines using Salama equation

Particle 8" BK-BP1 6" BJ-BB 12" BB-BP1 6" BF-BL 6" BH-BG 12" BH-BG

d (mm Vm range (m/s) % w Vm range % w Vm range % w Vm range % w Vm range % w Vm range % w

B

vm<0.066 1.2 vm<0.015 1.2 vm<0.171 1.2 vm<0.053 1.2 vm<0.157 1.2 vm<0.27 1.2 d<0,038

0.066<vm<0.07 0.1 0.015<vm<0.016 0.1 0.171<vm<0.181 0.1 0.053<vm<0.056 0.1 0.157<vm<0.167 0.1 0.27<vm<0.286 0.1 0,038<d<0,063

0.07<vm<0.074 14 0.015<vm<0.017 14 0.181<vm<0.192 14 0.056<vm<0.06 14 0.167<vm<0.177 14 0.286<vm<0.303 14 0,063<d<0,106

0.074<vm<0.077 26 0.016<vm<0.017 26 0.192<vm<0.2 26 0.06<vm<0.062 26 0.177<vm<0.183 26 0.303<vm<0.315 26 0,106<d<0,15

0.077<vm<0.081 44.5 0.017<vm<0.018 44.5 0.2<vm<0.211 44.5 0.062<vm<0.066 44.5 0.183<vm<0.194 44.5 0.315<vm<0.333 44.5 0,15<d<0,25

0.081<vm<0.084 9 0.018<vm<0.019 9 0.211<vm<0.22 9 0.066<vm<0.068 9 0.194<vm<0.202 9 0.333<vm<0.347 9 0,25<d<0,355

0.084<vm<0.09 3.9 0.019<vm<0.020 3.9 0.22<vm<0.233 3.9 0.068<vm<0.072 3.9 0.202<vm<0.214 3.9 0.347<vm<0.367 3.9 0,355<d<0,6

vm>0.09 vm>0.02 vm>0.233 vm>0.072 vm>0.214 vm>0.367 0,6<d

C

vm<0.067 6.98 vm<0.015 6.98 vm<0.175 6.98 vm<0.054 6.98 vm<0.16 6.98 vm<0.275 6.98 d<0,038

0.067<vm<0.071 6.7 0.015<vm<0.016 6.7 0.175<vm<0.185 6.7 0.054<vm<0.057 6.7 0.16<vm<0.17 6.7 0.275<vm<0.291 6.7 0,038<d<0,063

0.071<vm<0.075 13.36 0.016<vm<0.017 13.36 0.185<vm<0.196 13.36 0.057<vm<0.061 13.36 0.17<vm<0.18 13.36 0.291<vm<0.308 13.36 0,063<d<0,106

0.075<vm<0.078 23.59 0.016<vm<0.018 23.59 0.196<vm<0.203 23.59 0.061<vm<0.063 23.59 0.18<vm<0.187 23.59 0.308<vm<0.321 23.59 0,106<d<0,15

0.078<vm<0.083 22.29 0.017<vm<0.018 22.29 0.203<vm<0.215 22.29 0.063<vm<0.067 22.29 0.187<vm<0.198 22.29 0.321<vm<0.339 22.29 0,15<d<0,25

0.083<vm<0.086 5.15 0.018<vm<0.019 5.15 0.215<vm<0.224 5.15 0.067<vm<0.069 5.15 0.198<vm<0.206 5.15 0.339<vm<0.353 5.15 0,25<d<0,355

0.086<vm<0.091 7.51 0.019<vm<0.020 7.51 0.224<vm<0.237 7.51 0.069<vm<0.074 7.51 0.206<vm<0.218 7.51 0.353<vm<0.374 7.51 0,355<d<0,6

vm>0.091 vm>0.02 vm>0.237 vm>0.074 vm>0.218 vm>0.374 0,6<d

D

vm<0.066 0.06 vm<0.015 0.06 vm<0.172 0.06 vm<0.054 0.06 vm<0.158 0.06 vm<0.272 0.06 d<0,038

0.066<vm<0.070 0.87 0.015<vm<0.016 0.87 0.172<vm<0.182 0.87 0.054<vm<0.057 0.87 0.158<vm<0.167 0.87 0.272<vm<0.287 0.87 0,038<d<0,063

0.070<vm<0.074 6.16 0.016<vm<0.017 6.16 0.182<vm<0.193 6.16 0.057<vm<0.06 6.16 0.167<vm<0.177 6.16 0.287<vm<0.304 6.16 0,063<d<0,106

0.074<vm<0.077 39.2 0.016<vm<0.018 39.2 0.193<vm<0.201 39.2 0.06<vm<0.062 39.2 0.177<vm<0.184 39.2 0.304<vm<0.316 39.2 0,106<d<0,15

0.077<vm<0.082 14.5 0.017<vm<0.018 14.5 0.201<vm<0.212 14.5 0.062<vm<0.066 14.5 0.184<vm<0.195 14.5 0.316<vm<0.335 14.5 0,15<d<0,25

0.082<vm<0.085 17.11 0.018<vm<0.019 17.11 0.212<vm<0.221 17.11 0.066<vm<0.069 17.11 0.195<vm<0.203 17.11 0.335<vm<0.348 17.11 0,25<d<0,355

0.085<vm<0.090 22.1 0.019<vm<0.020 22.1 0.221<vm<0.234 22.1 0.069<vm<0.073 22.1 0.203<vm<0.215 22.1 0.348<vm<0.369 22.1 0,355<d<0,6

vm>0.090 vm>0.02 vm>0.234 vm>0.073 vm>0.215 vm>0.9369 0,6<d


Table 6.18 Flow critical velocity in several Bekapai pipelines using Salama equation (continued)

E

vm<0.066 0.48 vm<0.015 0.48 vm<0.170 0.48 vm<0.053 0.48 vm<0.156 0.48 vm<0.268 0.48 d<0,038

0.066<vm<0.070 2 vm<0.016 2 0.170<vm<0.180 2 0.053<vm<0.056 2 0.156<vm<0.165 2 0.268<vm<0.284 2 0,038<d<0,063

0.070<vm<0.074 3.91 0.015<vm<0.016 3.91 0.180<vm<0.191 3.91 0.056<vm<0.06 3.91 0.165<vm<0.175 3.91 0.284<vm<0.301 3.91 0,063<d<0,106

0.074<vm<0.077 4.61 0.016<vm<0.017 4.61 0.191<vm<0.198 4.61 0.06<vm<0.062 4.61 0.175<vm<0.182 4.61 0.301<vm<0.312 4.61 0,106<d<0,15

0.077<vm<0.082 6.52 0.017<vm<0.018 6.52 0.198<vm<0.21 6.52 0.062<vm<0.066 6.52 0.182<vm<0.193 6.52 0.312<vm<0.331 6.52 0,15<d<0,25

0.082<vm<0.085 3.73 0.018<vm<0.019 3.73 0.21<vm<0.218 3.73 0.066<vm<0.068 3.73 0.193<vm<0.2 3.73 0.331<vm<0.344 3.73 0,25<d<0,355

0.085<vm<0.090 35.22 0.019<vm<0.020 35.22 0.218<vm<0.231 35.22 0.068<vm<0.072 35.22 0.2<vm<0.212 35.22 0.344<vm<0.364 35.22 0,355<d<0,6

vm>0.090 43.54 vm>0.02 43.54 vm>0.231 43.54 vm>0.072 43.54 vm>0.212 43.54 vm>0.364 43.54 0,6<d

F

vm<0.065 4.36 vm<0.015 4.36 vm<0.17 4.36 vm<0.053 4.36 vm<0.156 4.36 vm<0.268 4.36 d<0,038

0.065<vm<0.069 7.02 vm<0.016 7.02 0.17<vm<0.18 7.02 0.053<vm<0.056 7.02 0.156<vm<0.165 7.02 0.268<vm<0.284 7.02 0,038<d<0,063

0.069<vm<0.073 19.13 0.015<vm<0.016 19.13 0.18<vm<0.191 19.13 0.056<vm<0.059 19.13 0.165<vm<0.175 19.13 0.284<vm<0.301 19.13 0,063<d<0,106

0.073<vm<0.076 15.81 0.016<vm<0.017 15.81 0.191<vm<0.198 15.81 0.059<vm<0.062 15.81 0.175<vm<0.182 15.81 0.301<vm<0.312 15.81 0,106<d<0,15

0.076<vm<0.081 17.34 0.017<vm<0.018 17.34 0.198<vm<0.21 17.34 0.062<vm<0.065 17.34 0.182<vm<0.193 17.34 0.312<vm<0.331 17.34 0,15<d<0,25

0.081<vm<0.084 13.08 0.018<vm<0.019 13.08 0.21<vm<0.218 13.08 0.065<vm<0.068 13.08 0.193<vm<0.2 13.08 0.331<vm<0.344 13.08 0,25<d<0,355

0.084<vm<0.089 21.55 0.019<vm<0.020 21.55 0.218<vm<0.231 21.55 0.068<vm<0.072 21.55 0.2<vm<0.212 21.55 0.344<vm<0.364 21.55 0,355<d<0,6

vm>0.089 1.71 vm>0.02 1.71 vm>0.231 1.71 vm>0.072 1.71 vm>0.212 1.71 vm>0.364 1.71 0,6<d

G

vm<0.069 3.51 vm<0.015 3.51 vm<0.17 3.51 vm<0.053 3.51 vm<0.156 3.51 vm<0.268 3.51 d<0,038

0.066<vm<0.070 10.76 vm<0.016 10.76 0.17<vm<0.18 10.76 0.053<vm<0.056 10.76 0.156<vm<0.165 10.76 0.268<vm<0.284 10.76 0,038<d<0,063

0.070<vm<0.074 17.24 0.015<vm<0.016 17.24 0.18<vm<0.191 17.24 0.056<vm<0.059 17.24 0.165<vm<0.175 17.24 0.284<vm<0.301 17.24 0,063<d<0,106

0.074<vm<0.077 13.13 0.016<vm<0.017 13.13 0.191<vm<0.198 13.13 0.059<vm<0.062 13.13 0.175<vm<0.182 13.13 0.301<vm<0.312 13.13 0,106<d<0,15

0.077<vm<0.082 18.32 0.017<vm<0.018 18.32 0.198<vm<0.21 18.32 0.062<vm<0.065 18.32 0.182<vm<0.193 18.32 0.312<vm<0.331 18.32 0,15<d<0,25

0.082<vm<0.085 13 0.018<vm<0.019 13 0.21<vm<0.218 13 0.065<vm<0.068 13 0.193<vm<0.2 13 0.331<vm<0.344 13 0,25<d<0,355

0.085<vm<0.090 18.78 0.019<vm<0.020 18.78 0.218<vm<0.231 18.78 0.068<vm<0.072 18.78 0.2<vm<0.212 18.78 0.344<vm<0.364 18.78 0,355<d<0,6

vm>0.090 5.26 vm>0.02 5.26 vm>0.231 5.26 vm>0.072 5.26 vm>0.212 5.26 vm>0.364 5.26 0,6<d


Table 6.18 Flow critical velocity in several Bekapai pipelines using Salama equation (continued)

H

vm<0.065 0.05 vm<0.015 0.05 vm<0.17 0.05 vm<0.053 0.05 vm<0.156 0.05 vm<0.268 0.05 d<0,038

0.065<vm<0.069 2.08 vm<0.016 2.08 0.17<vm<0.18 2.08 0.053<vm<0.056 2.08 0.156<vm<0.165 2.08 0.268<vm<0.284 2.08 0,038<d<0,063

0.069<vm<0.073 10.07 0.015<vm<0.016 10.07 0.18<vm<0.191 10.07 0.056<vm<0.059 10.07 0.165<vm<0.175 10.07 0.284<vm<0.301 10.07 0,063<d<0,106

0.076<vm<0.076 17.32 0.016<vm<0.017 17.32 0.191<vm<0.198 17.32 0.059<vm<0.062 17.32 0.175<vm<0.182 17.32 0.301<vm<0.312 17.32 0,106<d<0,15

0.076<vm<0.081 26.8 0.017<vm<0.018 26.8 0.198<vm<0.21 26.8 0.062<vm<0.065 26.8 0.182<vm<0.193 26.8 0.312<vm<0.331 26.8 0,15<d<0,25

0.081<vm<0.084 19.18 0.018<vm<0.019 19.18 0.21<vm<0.218 19.18 0.065<vm<0.068 19.18 0.193<vm<0.2 19.18 0.331<vm<0.344 19.18 0,25<d<0,355

0.084<vm<0.089 23.81 0.019<vm<0.020 23.81 0.218<vm<0.231 23.81 0.068<vm<0.072 23.81 0.2<vm<0.212 23.81 0.344<vm<0.364 23.81 0,355<d<0,6

vm>0.089 0.69 vm>0.02 0.69 vm>0.231 0.69 vm>0.072 0.69 vm>0.212 0.69 vm>0.364 0.69 0,6<d

*Particle A is not included in this calculation because it has no sieve analysis.


In general, sand will not settle in all Bekapai pipelines investigated here because actual mixture

velocity is larger than its critical value for each pipe. Fluid properties factor is negligible since all

flows are assumed to have same properties. The remaining factors are pipe diameter, particle

diameter, and liquid superficial velocity. These three parameters are proportional with critical

value. For example, the relationship between liquid superficial velocity and critical flow velocity is

illustrated in figure 6.17.

Figure 6.39 Critical velocity profiles in 6” BJ-BB, 6”BF-BL, and 6”BH-BG

Figure 6.17 shows that larger liquid superficial velocity will produce larger critical velocity (except

for particle F because the values are too small). This value is specific for each liquid superficial

velocity. Besides, the larger particle diameter, the larger critical velocity occurs.

According to their low values, sand particles are predicted to still move through pipe. Erosion risk

will be greater in this condition refer to sand concentration and the mixture velocity. Erosion is not

main focus in this report, but it is included in sand transportability phenomena along pipe. Erosion

is closely related to corrosion, which is defined as the phenomenon of a protective film of

corrosion product being eroded away by the erosive action of the process stream, exposing fresh

metal which then corrodes (API 14 E).

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

8.22E-05 9.38E-02 1.41E-01

crit

ical

vel

oci

ty (m

/s)

liquid superficial velocity (m/s)

Particle A

Particle B

Particle C

Particle D

Particle E

Particle F

Particle G

Particle H


6.2.2 Vertical Pipe

In his paper (1998), Salama suggested Chien’s model to predict sand settling velocity. This model

does not considered pipe diameter factor so that the critical velocity value is same for each

particle in all pipelines. Considering the diameter range of each particle, information about flow

critical velocity can be seen as also in ranges (Figure 6.40).

Table 6.19 Actual mixture velocity in vertical Bekapai pipeline for each particle

Pipeline

Liquid velocity (m/s)

mixture velocity (m/s)

8 inch BK-BP1 0.04 1.28 6 inch BJ-BB 0.0008 0.48 12 inch BB-BP1 0.67 1.59 6 inch BF-BL 1.64 5.14 6 inch BH-BG 1.14 3.26 12 inch BL-BA 2.21 7.72

Figure 6.40 Range of critical velocity in several Bekapai pipelines based on particle diameter

0

5

10

15

20

25

30

35

40

45

50

% w

eigh

t

critical velocity (m/s)

particle B

particle C

particle D

particle E

particle F

particle G

particle H

38 µm<d<6

3 µm

355µm<d<600

µm

250 µm<d<355 µm

150 µm<d<250 µm

106 µm<d<150 µm

63 µm<d<106 µm

d>600 µm

d<38 µm


Sand dune formation will be created if critical flow velocity is smaller than mixture velocity.

When particle diameter becomes larger, it has bigger possibility to settle down. According to

each particle size, one particle tends to have different critical velocity. Table 6.15 shows that

only particle with diameter > 600 µm (particle E, F, G, and H) will settle in 6”BJ-BB pipelines.

Because the pipe position is vertical, most of the sand particles will settle at 90O elbow before

riser. Particle H seems to be found in high concentrate than the others (43.5%).

Since particle size has not been known exactly except in range form, these particles still have

chances to settle among other pipelines. In pigging report during year 2010 in Bekapai, sand has

been found in 12” BL-BA, 12” BB-BP1, and 6” BF-BL. This has been proven by fluid velocity in 12”

BB-BP1 (1.28 m/s) which is not too high. In BF-BL and 12” BL-BA cases, settling phenomena may

be came from particle size and high sand concentration from wellbores.

Annular regime in vertical Bekapai pipelines indicates high gas velocity. This is may be a good

news to find that sand settling has not the main concern in oil-gas transportation along sea line

and riser yet because sand particles will easily be swept away. But sand usually has higher

concentration in liquid phase (liquid velocity in each pipeline can be seen in Table 6.15). Sand

particles (E, F, G, and H) are predicted to be found in 8” BK-BP1 and 6” BJ-BB.

6.2.3 Main Finding

The important factors that affect sand settling phenomenon are particle diameter, fluid density,

liquid velocity, kinematic viscosity, and pipe diameter. Chien was not considered the last two

parameters in his correlation so that for same particle, it has the same critical velocity although

the pipeline properties are different. In Bekapai case, sand settling is likely occurred in vertical

flow than horizontal one. Only BJ-BB has sand settling problem with particle E, F, G, and H while

the others cannot be definitely decided. Sand possibility to settle in the other pipelines is still

need to be considered and anticipated seriously.


Since specific information of sand particles in each pipeline had not been received until this report

was finished (all particles used in this analysis are not the real particle found in those pipelines),

the above conclusions cannot be fully accepted. It means sand behavior in Bekapai pipelines is still

very complex and need to be studied further with the real model of Bekapai pipelines and

adequate data about specific sand particles.


CHAPTER VII

CONCLUSIONS AND RECOMMENDATIONS

7.1 Conclusions

Oil-gas-water flow including sand transportation in pipeline is affected by many factors, such as

flow regime, liquid holdup, fluid velocity, fluid properties, pipe properties, etc. Sand behavior and

flow regime are interrelated but until now there is no exact correlation made to wholly describe

the sand settling phenomena in each regime.

In Bekapai case, parameters like pipe diameter and fluid properties should be put into sand

transport consideration. They give a big impact of flow regime and flow critical velocity

estimation. They may become a good reason why OLGA is chosen between the other models to

determine multiphase flow properties. Beggs & Brill and the other correlations depend strongly on

the fluid and pipe diameter in their origin experimental investigation.

Another important parameter in sand transportation is the effect of pipe geometry (i.e. pipe

diameter). This is the key to solve problem about flow critical velocity determination. Salama and

Chien provide correlation without sufficient attention about this (i.e. 90o elbow between sea line

and riser). As consequences, their results regarding critical velocity to avoid sand bed formation

must be ensured with another model that capable to illustrate multiphase flow phenomena,

especially in the transition section between sea line and riser. In this analysis, only OLGA has

powerful basic and applicable to be used in several Bekapai pipelines which already oversized due

to production decline. Prediction like oil blockage and slug formation (8”BK-BP1 and 12”BB-BP1)

can be used to support further analysis of sand transportability in Bekapai pipelines.

7.2 Recommendations

It is recommended to take a precaution over sand accumulation, especially at the riser bottom

or another transition section of pipelines due to analysis results. Fluid mixture velocity should

be enhanced until exceed the critical flow velocity to prevent initial sand bed formation.


Routine pigging should be done in pipelines that have been detected to experience sand

settling. Some pipelines which have low fluid mixture velocity (6” BJ-BB, 8” BK-BP1, and 12”

BB-BP1) should be placed at top priority.

Because sand settling phenomena strongly depends on the present data of fluid volumetric

rate in pipelines, this analysis is recommended to be routinely updated.

It is recommended to use OLGA instead of Beggs & Brill and experimental correlation in

application to determine multiphase flow properties, especially flow regime and dynamic

behavior of each parameter included.

It is recommended to do further study and analysis about this topic, especially about the other

parameters correlation that affecting sand behavior (e.g. pipe geometry and fluid properties).

It is better to use real model of Bekapai pipelines and fluid in order to be applied in the future.

analysis of sand transportability in pipelines

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