Analysis of Sand Transportability in Pipelines

ANALYSIS OF SAND TRANSPORTABILITY IN PIPELINES

STUDY REPORT

Author

07/2010

Laras Wuri Dianningrum

Check and Verify Patria Indrayana FO/AMB/MTH

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

ii

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

iii

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

iv

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 oilgas flow (8” BK-BP1) ............................................................................................................. 53 TABLE 6.7 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oilgas flow (12” BB-BP1) ........................................................................................................... 56 TABLE 6.8 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oilgas flow (6” BF-BL) ............................................................................................................... 59 TABLE 6.9 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oilgas flow (6” BH-BG) .............................................................................................................. 62 TABLE 6.10 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in oilgas 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 TABLE 6.12 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in water-gas flow (6” BH-BG).................................................................................................... 70 TABLE 6.13 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in water-gas flow (6” BF-BL) ..................................................................................................... 73 TABLE 6.14 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in water-gas flow (6” BJ-BB) ..................................................................................................... 75

v

TABLE 6.15 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in water-gas flow (8” BK-BP1) ................................................................................................. 78 TABLE 6.16 Flow regime, holdup, and fluid velocity comparisons between OLGA and Beggs & Brill in 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

vi

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

vii

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

viii

ix

Analysis of Sand Transportability in Pipelines

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

Analysis of Sand Transportability in Pipelines

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

2

Analysis of Sand Transportability in Pipelines

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.

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Analysis of Sand Transportability in Pipelines

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

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Analysis of Sand Transportability in Pipelines

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).

5

Analysis of Sand Transportability in Pipelines

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,

6

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

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

6

Analysis of Sand Transportability in Pipelines

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.

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Analysis of Sand Transportability in Pipelines

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 = Where 𝑥𝑖 𝑣𝑖

= mol fraction of each component = molar volume of each component

𝑣𝑚𝑖𝑥 = molar volume of the mixture

𝑥𝑖 𝑣𝑖

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Analysis of Sand Transportability in Pipelines

 Liquid mixture viscosity (Campbell, 2004) For determining liquid mixture viscosity, the below equation is used. 𝜇𝑚𝑖𝑥 = Where 𝑥𝑖 𝜇𝑖

𝑥𝑖 (𝜇𝑖 )1/3

3

= mol fraction of each component = 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 = Where 𝜌𝑤 𝜌𝑕

1.58 𝜌𝑤 − 𝜌𝑕 + 1.76

4

𝑇𝑟 0.3125

= water density = 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 /𝑇𝑝𝑟 2 𝑎 = 0.1219𝑇𝑝𝑟 0.638 𝑏 = 𝑇𝑝𝑟 − 7.76 +

14.75 𝑇𝑝𝑟

𝑐 = 0.3𝑥 + 0.441𝑥 2 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

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Analysis of Sand Transportability in Pipelines

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).

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Analysis of Sand Transportability in Pipelines

Experimental correlation

Catagory A

Catagory B

(No slippage and no flow pattern consideration)

(Slippage considered, no flow pattern consideration)

(Slippage and flow pattern consideration)

Pettmann&Carpenter,B axendel&Thomas,Fanch er&Brown

Hagedorn&Brown,Gray, Asheim

Dun&Ros,Orkiszewski,A ziz,etc

Catagory C

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

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Analysis of Sand Transportability in Pipelines

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

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Analysis of Sand Transportability in Pipelines

The characteristic of each regime explained as follows:

Dispersed Flow

Segregated Flow

Intermittent Flow

Stratified

Bubble

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

(Small gas -liquid ratio, continuous phase: liquid, very low slip velocity)

Annular

Mist/Spray (Very high gas flow rate, very high gas-liquid ratio, continuous phase: gas)

(very high gas-liquid ratio, high gas flow rate, annular film on the wall is thickened at the bottom of pipe)

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)

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.

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Analysis of Sand Transportability in Pipelines

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:

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Analysis of Sand Transportability in Pipelines



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.

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Analysis of Sand Transportability in Pipelines

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.

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Analysis of Sand Transportability in Pipelines

The coordinates used in the Aziz vertical map are: 𝑁𝑥 = 𝑉𝑠𝑔 𝑋𝐴 𝑁𝑦 = 𝑉𝑠𝑙 𝑌𝐴

Where

0.333

𝑋𝐴 =

𝜌𝑔 𝜌𝑎

𝑌𝐴 =

𝜌𝑙 𝜎𝑤𝑎 𝜌𝑤 𝜎

𝑌𝐴 0.25

𝑁𝑥 , , 𝑁𝑦 , 𝑋𝐴 and 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 twophase 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.

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Analysis of Sand Transportability in Pipelines

Table 3.1 Multiphase flow correlations Correlation Vertical Upward Flow Duns & Ros Angel-Welchon-Ross Hagedorn & Brown Orkiszewski

Aziz

Beggs & Brill

Gray Horizontal Flow Lockhart-Martinelli

Eaton

Dukler

Beggs&Brill Inclined Flow Mukherjee-Brill

Notes Good in mist and bubble flow regions. Applicable for high flow areas and annulus flow. Recommended for high volume wells and low gas/oil ratios Best available pressure drop correlation for vertical upward flow Most accurate for angles of inclination greater than 70 degrees Result reliable for high gas/oil ratios Most accurate for angles of inclination greater than 70 degrees Generally slightly overpredicts pressure drop; other correlation tend to underpredict. This fact can be used to bracket the solution. Most accurate for angles of inclination greater than 70 degrees Good for all angles of inclination. Predicts the most consistent results for wide ranges of conditions. Specifically designed for condensate wells (high gas/oil ratios) Recommended ranges: velocity< 15 m/s 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 Do not use for diameters0.374

0,6