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TheImpactofIncreasingDepthandDiameteronPredictionofFlowRegimeTransitioninDeepwaterFlowlinesandRisers

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IPTC-18546-MS

The Impact of Increasing Depth and Diameter on Prediction of FlowRegime Transition in Deepwater Flowlines and Risers

N. U. Okereke, and F. Kara, Cranfield University; S. C. Omowunmi, Total Upstream Nigeria (TUPNI);

M. Oyawale, and I. Adefemi, Cranfield University

Copyright 2015, International Petroleum Technology Conference

This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, 6–9 December 2015.

This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s).Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s).The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Paperspresented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restrictedto an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paperwas presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax � 1-972-952-9435

Abstract

This work is based on simulation of a typical deepwater oil field in West-Africa over 1000m depth, whichis subject to hydrodynamic slugging at its early life. Sensitivity analysis was carried out to simulate theimpact of increasing depth and diameter on the field with the same fluid composition and slight variationin pressure and mass flow conditions.

Based on US MMS, fields found in water depth of 1000 ft (305m) and above are termed deepwaterfields. Typically, for deepwater oil fields the ambient temperature is low giving room for formation ofcompounds such as hydrates and wax. Also of critical concern is the increasing depth associated withdeepwater oil fields which leads to increasing hydrostatic pressure and its associated tendency forslugging formation. Increasing diameter has the tendency to lead to a drop in fluid velocity. However,there are still speculations as to the exact effect of increasing diameter on flow instability which is oneof the main aspects of the present work [1].

An understanding of the multiphase flow phenomenon as well as the overall potential effects on theprocessing facilities is required in the design of the multiphase flowlines. An under-design or overdesignof the piping can be counterproductive and may significantly affect the process plant operability.Therefore emphasis is placed on understanding completely, flow assurance issues in the multiphase flow;especially slugging phenomenon as flowline-riser system diameter and depth is increased.

IntroductionSlugging phenomenon is a major flow assurance issue in multiphase flow. It results in alternate deliveryof liquid which �results in alternate delivery of liquid and gas phases�. This alternate delivery of thedifferent phases is due to the difference in travelling velocities (superficial velocities) of the phases. Thiscan also cause liquid surges within the pipes. Slugging has the tendency to reduce production by up to50% as highlighted in previous study in literature. It becomes even more critical in deepwater oil fieldswith tall risers and large hydrostatic pressure.

When subsea production systems are designed, assessment of slugging is often focussed on handlingthe liquids that arrive at the topsides facilities. However, recent field experience in the deepwaterGulf-of-Mexico shows that the gas surges behind the liquid slugs, rather than the slugs themselves, canbe more challenging. Gas surging due to hydrodynamic slugging is particularly challenging for �full�subsea production hubs with minimal gas compression capacity, which if uncontrolled can lead to topsidestrips and production constraints. Also, the need for a clearer understanding of slug mechanism, especiallythe interaction between the taylor bubbles (gas surges) and the liquid slug in the slug body as diameterand depth increases cannot be over-emphasized.

Multiphase slug flow is a very undesirable flow regime, as a result of the associated instabilities whichinitiates major flow assurance challenge, in transporting the reservoir fluid from upstream reservoirlocation to the downstream topsides processing facilities. Slug flow, is one of the predominant flowassurance issues, encountered regularly in deepwater oil and gas production. As earlier discussed, slugflow can occur both in horizontal and vertical flow. Hence there are different types of slugs which can bedistinguished from each other based on the mechanism of formation namely:

Hydrodynamic SluggingOperation Induced SluggingSevere Slugging

However, for the purpose of this work, only hydrodynamic slugging and severe slugging are consid-ered.

Prediction of the phase behaviour of typical two phase (gas-liquid) flow in deepwater flowline-risersystem is not yet well understood. The challenge of accurately predicting the transition in flow regimebecomes even more difficult with increasing depth and diameter of flowlines and risers, as most initialcorrelations developed for the purpose of such prediction were based on smaller diameter pipe sections;such as 2� and 4� used in air-water experimental set-up. This study is focussed on assessing typicaldeepwater oil fields, with the intent of gaining a better understanding of the behaviour of the gas and liquidphase, as flowline-riser diameter and depth are being increased. OLGA (OiL and GAs) simulations areperformed to ascertain the impact of increasing diameter and depth on flow regime transition.

This study involves further sensitivity analysis in development of OLGA model of a typical deepwateroil field in West Africa. Simulation is then run at 1400m, 2000m and 3000m for 8 inches, 10 inches and12 inches flowline-riser systems. Key parameters such as; pressure, gas superficial velocity, liquidsuperficial velocity and flow regime ID are assessed in terms of their profile plots and trend plots.

The flowline-riser profile is defined in OLGA and simulations are run for over 700 data points atcritical points selected along an 8� pipe profile. The critical points on the pipeline-riser system includes;inlet point, manifold point, riser-base and topsides. Over 40 mass flowrate values were run and at differentwater-cut rates. The critical mass flowrate and water-cut scenarios that lead to transition to slug flow, werealso observed. Variation in depth and diameter was also integrated in the simulation to assess its impacton flow regime transition prediction.

Currently, the results show transition to slug flow for low mass flowrate range of less than 3000 bopdat a water-cut of 30% for the 8� diameter pipeline-riser system; for a water depth of about 1,200m. Furtherincrease in the flowline-riser diameter to 12�, 16�, 24� and 32� indicates so far that slugging tendencyincreases especially between the riser-base to topsides with increasing diameter. Also this transitionoccurs between the riser-base and the topsides. Hence, increasing pipeline-riser diameter leads toreduction in pressure drop and liquid accumulation around the riser-base with subsequent reduction insuperficial gas velocity, leading to unsteady (gas-liquid) phase (slugging) in the system. The impact ofincreasing depth is also being assessed.

Doty and Dale [2] presented three separate severe slugging transition criteria:

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● Stratified-non stratified flow transition; i.e they postulate that the flow in the pipeline segmentbefore the riser has to be stratified for severe slugging to occur.

● The stability of the flow in the riser, i.e when the pressure drop in the riser decreases as the gasflow rate increases for a given liquid flow rate then the flow is said to be unstable and susceptibleto severe slugging.

● The criterion in allocating the boundary between severe slugging and transition to severe sluggingis a direct solution of their hydrodynamic model for the lowest gas flow rate corresponding to aliquid flow rate that will produce riser generated slugs shorter than the riser length.

Also, according to Boe [3], the forces that are acting on a liquid slug blocking the entrance into the riserfor the occurrence of severe slugging, namely the gas pressure that is building up in the pipeline and thehydrostatic head of the liquid in the riser.

Part of this work involves assessing how increasing diameter and depth will impact on these criteria.Based on study by Andritsos and Hanratty [4], the key difference of pipe size or diameter on the

mapping of flow regime for air-water flow in a 2.54cm pipe and in a 9.53cm pipe is the strong effect ofpipe size on the critical liquid velocity needed to generate slugs at low gas velocities.

Instability of stratified flow is also prone to occur as we reduce pipe internal diameter with reductionin pressure.

The coalescing of waves into slug formation is more prone to occur with reduction in pipe size and fluidoperating at low superficial velocity for both gas and liquid.

In view of the simulations run so far, increasing diameter leads to flow being stratified. This becomesso as increase in diameter gives rise to drop in gas superficial velocity along the flowline-riser system. Thenature of flow in pipe, based on work by Osborne Reynolds is dependent on the pipe diameter, the densityand viscosity of the flowing fluid and the velocity of the flow. Dimensionless Reynolds number is used,and is the combination of these four variables and may be considered to be the ratio of dynamic forcesof mass flow to the shear stress due to viscosity. Reynolds number is:

Where parameters are: D - internal diameter, v - velocity; � - density; v - kinematic viscosity;� - dynamic viscosity.

In view of the above equation, increase in diameter alone, may not influence flow regime transition,however increase of diameter plays a critical role in flow regime formation.

Increase in depth leads to increase in pgh/hydrostatic pressure and hence making it difficult to conveythe multiphase fluid stream to the topsides.

In this study, focus was on a sample deep-water oil field off the coast of West Africa. The field liesin a water depth of about 1447.8m below mean sea level. It consists of twenty production wells centredon six drilling centre manifolds. The production wells are tied to the FPSO (Floating Production Storageand Offloading) vessel by eight (8) production risers. Currently, sixteen (16) of the production wells havebeen drilled and are in production. The field currently produces over 200,000 BoPD. A critical review wasdone on the flow loops connecting the following relevant wells (X1, X10, X3 and X5), in order tounderstand the wells that are hooked up to Flow Loop X1. The wells are connected via a pipeline-risersystem, to the topsides. X1 and X2 are connected via MFX1 (Manifold X1). X3, X4 and X5 areconnected via MFX2 (Manifold X2). X10 and X11 are connected via MFX6 (Manifold X6). Flow LoopX1 from the field report obtained experienced hydrodynamic slugging when it was operating at 3000BoPD in the early life of the field. Table 1 shows the pipeline-riser co-ordinates and section lengths forFlow Loop X1.

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The details of the flow loops geometry connecting the wells (X1, X10, X3 and X5) as well as pressureand temperature readings at the core points are as highlighted in Table 3.

The fluid composition is as shown in the Table 2 above. The fluid in question is a relatively light oilof API 47 degree. It consists of relativey high molar composition of methane (43.3 Mol. %). It’s Heptaneplus composition is also relativey high (28.83 Mol. %). This composition as well as the pipe configuration

Table 1—Pipeline-Riser Co-Ordinates and Section Lengths for Flow Loop X1

Table 2—Fluid Properties of Field Data

Component

Composition (Mol. %)

Well X1 and X2

Carbon Dioxide (CO2) 0.81

Nitrogen (N) 0.13

Methane (CH4) 43.3

Ethane (C2H6) 7.49

Propane (C3H8) 7.29

Iso-Butane (iC4) 2.61

N-Butane (nC4) 3.28

Iso-Pentane (iC5) 1.98

N-Pentane (nC5) 1.56

Hexanes (C6H14) 2.72

Heptane Plus (C7�) 28.83

Table 3—Flow Geometry, Pressure and Temperature Readings at Core Loop Points

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with about 1500m riser height makes it a bit difficult for stable fluid flow to the riser at relatively low massflowrate.

From Figure 1 and Table 1, Well X1, the well at the inlet of the flow loop in consideration was locatedon the seabed in a water depth of 1447.8 m below mean sea level and is located about 2,700 m from thebase of the riser. The topsides vessel (FPSO) stands in water with its production deck located some 49 mabove sea level. The vertical riser connected to the production vessel is at water-depth 1513.03 m, withI.D (internal diameter) of 8 inches and a combined steel wall and insulation thickness of 11 mm with piperoughness of 0.002m.

The pressure at the topsides separator is constant and given as 20 bara. Assumption is made on theminimum arrival temperature at the production vessel is 72.8 °C. The maximum allowable pipeline inletpressure is set at 150 bara for a flowrate of 6722 BoPD. The field wellhead pressure is 125 bara. Theminimum ambient temperature of the seabed is assumed to be set at 5 °C while the ambient heat transfercoefficient is assumed to be 2.3W/m2/K for the pipeline-riser system.

In Figure 2, the field pressure profile was compared with the simulation pressure profile for validationpurpose. Firstly, the field data did not capture pressure data at the wellhead and this was highlighted inthe result. Pressure values of both the field data and simulation results were matched at the topsidesbecause simulation was based on exactly the same fixed separator arrival pressure as in Table 3. It is alsoimportant to note that the over-prediction of pressure by OLGA is similar to the trend obtainable inliterature.

Figure 1—Geometry of Flow Loop X1 Pipeline-Riser System Showing the Profile from Seabed to Topside

IPTC-18546-MS 5

The similarity in pressure trend shown in Figure 2 is also another basis for confidence in furthersimulation results of the field case study.

Pressure comparison results for validation, to build confidence for further simulation work.In Figure 3 above, a generic pipeline-riser system, with a riser height of 2000m was adapted from Flow

Loop X1. Along the pipeline section, the pipeline is inclined downwards towards the riser-base which ispositioned at 2712m point along the pipeline section. Simulations were run on this pipeline-riserconfiguration, in order to ascertain the impact of increasing riser height on flow regime transition,especially transition into the slug flow regime. The simulations were run for 24 hours for each massflowrate condition considered.

In Figure 4 above, a generic pipeline-riser system, with a riser height of 3000m was adapted from FlowLoop X1. Along the pipeline section, the pipeline is inclined downwards towards the riser-base which is

Figure 2—Field Data Vs Simulation Result Comparison (Pressure)

Figure 3—Generic 2000m Pipeline-Riser System

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positioned at 2712m point along the pipeline section. However, it is important to note that the inclinationis not as steep as the pipeline-riser system in Figure 3. Simulations were run on this pipeline-riserconfiguration, in order to ascertain the impact of further increasing riser height on flow regime transition,especially transition into the slug flow regime.

Simulation Results and Discussion:Based on the simulation results, it is clear that increase in the flowline-riser diameter gives rise to areduction in gas superficial velocity and consequently the tendency for liquid accumulation at low pointsand possible slug formation depending on the superficial gas velocity and the pipeline inclination. We alsoobserve that increase in the pipe diameter at a particular riser depth gives rise to a reduction in the pressurefluctuations especially around the riser-base. From the plots obtained, the pressure trends indicates areduction in the pressure fluctuation cycle for the case with 2000m and 3000m water depth at increasingdiameter of 8 inches and 10 inches. However, increase in diameter from 10 inches to 12 inches, did notyield a drop in pressure fluctuation, both for the 2000m case and the 3000m case.

Depth Effect:As depth increases as we go deeper waters, the tendency is for hydrostatic pressure to increase withincreasing gravitational effect and especially with relatively dense multiphase fluids. This will also impacton flow stability and that forms the crux of this study.

Key ResultsKey results highlighting on the impact of increasing depth to flow stability and transition into slug flowregime are captured Figure 5 to Figure 10.

In Figure 5, the result shows the pressure trend derived by slightly modifying Flow Loop X1 into ageneric pipeline-riser system with 2000m riser height and 8� diameter. Regular pressure fluctuationbetween 70 bara and 85 bara was observed at the riser base. This is quite a reasonable pressure fluctuationcapable of generating slugs at the riser-base.

Figure 6, shows a pressure trend for the same 2000m pipeline-riser system but with 10� diameter. It canbe clearly observed that there was a drop in the range of pressure fluctuation for the 10� diameterpipeline-riser system to (58 to 61.5 bara) as compared to the 8� diameter pipeline-riser system with a

Figure 4—Generic 3000m Pipeline-Riser System

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Figure 5—Pressure Trend at RB in the 2000m Case for 8� Pipeline-Riser System

Figure 6—Pressure Trend at RB in the 2000m Case for the 10� Pipeline-Riser System

Figure 7—Pressure Trend at the RB for the 2000m Case for 12� Pipeline-Riser System

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Figure 8—Pressure Fluctuation Trend at 3000m for 8� Flowline-Riser System

Figure 9—Pressure Trend at MF and RB at 3000m Depth for 10� Pipeline-Riser System

Figure 10—Pressure Trend at MF and RB at 3000m Depth for 12� Pipeline-Riser System

IPTC-18546-MS 9

pressure fluctuation range of (75 to 85 bara). This scenario is observed at the riser-base reflected as(RB-FPSO) on the simulation run.

Figure 7 shows the results obtained from the 24 hours simulation on the 2000m pipeline-riser systemfor a 12� diameter. The trend shows a sudden pressure fluctuation with relatively high amplitude between40 Bara to 140 Bara. The frequency of the fluctuation is also relatively regular and high. This pressurefluctuation is a function of the increased diameter of the pipeline-riser system (which in this case is 12�).This suggests that the 12� pipeline-riser system has the tendency to give rise to greater liquid accumulationat the riser-base with its consequent effect of an increased pressure fluctuation.

In Figure 8, consideration was given to 3000m case at 8� pipeline-riser diameter. The results also showhigh degree of pressure fluctuation between 133 bara to 140 bara. This high pressure fluctuation could beattributed to the increased riser height and the relatively small pipe diameter. This range of pressurefluctuation has tendency to cause riser-base induced slugging (severe slugging) as well as impact of thepipeline-riser structure in terms of fatigue.

In Figure 9, the 3000m - 10� diameter case, a drop in the pressure fluctuation was observedto between(121 bara to 123.5 bara) was observed; however the fluctuation was still relatively regular. This wasobserved both at the manifold region and the riser-base.

In the 3000m - 12� diameter case as reflected in Figure 10, a relatively regular fluctuation with largeamplitude ranging between 56 bara to 155 bara is observed. There seems to be a trend of the pressurefluctuation dropping from 8� to 10�, but suddenly increasing when the pipe diameter was increased to 12�.The sudden increase in pressure fluctuation when the pipe diameter increased to 12� could be attributedto the large diameter leading to increased accumulation of liquid at the riser-base with tendency ofincreased fluctuation over time.

Diameter Effect:Based on [1], speculation is given to the impact of changes in diameter of pipeline-riser sections and theunderlying physical phenomena of fluid flow; especially transitions between flow regimes. This sectionis therefore focussed on a rigorous study and sensitivity analysis on the effect of increasing diameter anddepth on flow regime transition in the Flow Loop X1 case study, with particular emphasis on sluggingbehaviour at selected points on the Flow Loop X1.The key points selected include the manifold (MF),Riser-Base (RB) and topsides (TP). These points were chosen as a result of the extra flow from themanifold that is tied in to the main flow loop, which from preliminary studies, gave rise to some dynamicsto the flow; in order to observe the effect at that point. The riser base was also selected because of thechange in geometry that occurs there to evaluate the impact of diameter change at that point.

From the diameter effect plot in Figure 11, it can be observed that with increasing diameter, thesuperficial velocity gas (Usg) drops at the MF (manifold region), leading to liquid accumulation at lowpoints and consequently gas-liquid phase instability generating slugging in Flow Loop X1.

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A steady drop in superficial velocity gas at the riser-base with increasing diameter from 8�(0.2032m)to 32� (0.8128m) at M16 in Figure 12 was observed. This drop in superficial velocity gas as highlightedin literature earlier has the tendency to cause liquid accumulation; especially if the Usl (superficialvelocity liquid) is relatively low. This type of scenario poses threat of slug formation.

From Figure 13, a steady drop in superficial velocity gas with respect to increasing pipe diameter wasalso observed for the diameter effect plot at the topsides at M16. It is pertinent to mention that thiscondition in the topsides will not pose threat to the chokes and valves at the separator, as the flow willnot fluctuate. However, the downside is that a low Usg might make it difficult for a continuous flow ofthe multiphase stream to the topsides with the accumulation of liquid that will build up over time.

Figure 11—M16 Diameter Effect Study at MF on Flow Loop X1

Figure 12—M16 Diameter Effect Study at RB on Flow Loop X1

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Flow Regime Transition Charts:Flow regime transition charts have existed since the 1970s and provides basis for industry to sizepipeline-risers systems. However, existing maps such as the horizontal map by Mendahane et al. [5] andunified map for whole range of pipe inclinations Barnea [6] are limited because they are based on smallpipe diameters and air and water fluid package. Hence, part of the focus of this work is aimed to addressthat gap by attempting to develop flow regime transition charts based on typical sample field fluid packageas well as sample field geometry for deepwater scenario.

Stratified-Slug Flow Transition Theoretical BackgroundIn stratified gas-liquid horizontal flow, long wavelength waves grow, reaching the top of the pipe to formslug flow at certain flow conditions. At certain flow conditions also, slugs may grow to become extremelylong to for instance up to 500 pipe diameter [7]. The presence of long slugs often causes upsets inoperations and a reduction in the flow efficiency. Hence, predicting the flow conditions at which slugs;especially long slugs appear contributes to a better design and flow management to optimize the flowefficiency. In this study, consideration was given to typical transition that occurs in Flow Loop X1 (atypical deep-water oil flow loop); in order to gain an insight into the flow conditions that initiate transitioninto slug flow regime. Mass flowrates conditions ranging from M16 - M45 (defined in Appendix 2) weresimulated under water-cut conditions ranging from 3% WC to 60% WC. The transition in flow regimesexperienced in the flow regime charts can be defined by one (or more) of three criteria: a viscous linearinstability of a stratified flow to long wavelengths disturbances; the stability of a slug; and Kelvin-Helmhotz instability of a stratified flow [7].

The key novelty of this work includes;

● Consideration of water-cut and variation of mass flow rates in order to evaluate the impact ofwater-cut and variation of mass flow-rates on flow regime transition along core points (Inlet,Manifold region and Riser-Base) on the Flow Loop X1.

In Figure 14, M1 flow condition was run for 24 hours on the 8 inches generic 2000m pipeline-riserconfiguration. 724 Trend data points were generated from the runs which were now used in developingthe flow regime transition chart at M1 condition. M1 is as defined in Appendix 1. In Figure 14, flowexisted mainly in the stratified region because of the pipeline inclination before the riser-base which

Figure 13—M16 Diameter Effect Study at TP on Flow Loop X1

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caused the liquid phase to flow predominantly along the pipeline base as a result of gravitational effecton the liquid phase. The relatively light fluid of API 47 also contributed to the ease of flow to the topsides.

In Figure 15, M1 flow condition was also run for the 8 inches generic 3000m case. The pipeline riserconfiguration also influenced the stratification of the flow as a result of gravity effects. However, theincrease in riser height influenced the degree of disturbance of the stratified flow regime experienced.

The mass flowrate conditions run are: Mgas � 1.25kg/s; Moil � 1.45kg/s and Mwater � 2.80kg/s atSource 1 and Mgas � 1.53kg/s; Moil � 3.53kg/s and Mwater � 2.53kg/s Source 2. The instability in thestratified regime suggests tendency for possible transition into slug flow regime as mass flowratesincreases. 724 Trend data points were also ran in this case.

In Figure 16, the mass flow rate condition was increased to M2 as defined in Appendix 1. Simulationwas also run for 24 hours and 724 trend data points for superficial velocity gas and liquid extracted to plotthe transition chart. At a relatively lower riser height of 2000m, the flow regime showed a relatively stable

Figure 14—Flow Regime Transition at Ml for 8� Pipeline-Riser System - 2000m

Figure 15—Flow Regime Transition at Ml Condition for 8� Pipeline-Riser System - 3000m

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stratified flow existing between a superficial velocity gas of 3m/s to 4m/s and a superficial velocity liquidof 0.4m/s to 0.6m/s.

In Figure 17, as the riser height was increased still at the same M2 flow condition, disturbance wasintroduced at the gas-liquid interface, leading to the slight degree of instabilioty noticed in the existingstratified flow regime.

In Figure 18, there was a further increase in the mass flowrate condition run to M15. In the 8 inchesgeneric 2000m case, there was formation of annular flow as a result of the increased superficial gasvelocity at the core of the pipeline-riser section. 724 Trend data points were also generated for this case.Slug flow was observed at a relatively lower Usl (superficial liquid velocity).

Figure 16—Flow Regime Transition Chart at M2 for 8� Generic Pipeline-Riser System - 2000m

Figure 17—Flow Regime Transition Chart at M2 for 8� Generic Pipeline-Riser System - 3000m

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In Figure 19, similar high mass flowrate (M15) deployed in Figure 18 case was used. The simulationwas also run for 24 hours and 724 trend data points were extracted. The increase in riser height to 3000minfluenced transition by causing slug flow to exist at relatively higher Usl of 3.25m/s as compared to the2000m riser height case. Annular flow in this case was also occurred at a relatively lower Usl of 1m/s andUsg of 1m/s.

In Figure 20, slugging is observed occurring at low superficial gas velocity (Usg) range of 1.0m/s toabout 4.5m/s. Bubble flow is observed occurring within a Usg range of 3.0m/s to 5.0m/s and Usl rangeof 4.20m/s to 6.5m/s. It is important to note that the behaviour of slugging occurring at predominantly lowsuperficial gas velocity at the riser-base is similar to the trend of behaviour at low superficial gas andliquid velocities reported by Woods and Hanratty [8].

Figure 18—Flow Regime Transition at M15 for 8� Generic Pipeline-Riser System - 2000m

Figure 19—Flow Regime Transition Chart at M15 for 8� Generic Pipeline-Riser System - 3000m

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Summary of Transition Charts ResultsIn summary, the results from the transition charts suggest that flow regime transition in pipeline risersystems is influenced primaruily by the mass flowrate condition, water-cut as well as the pipe-riserconfiguration. Results from this work also suggests that increasing riser heights increases the instabilityin the gas-liquid phase interface; thereby creating disturbance that initiates transition from stratified toannular, slug or bubble flow regime, depending on the mass flowrate condition.

Conclusion and RecommendationKey conclusions from the background and simulation results are as follows;

● Increasing diameter will lead to a reduction in pressure fluctuation along the pipeline-riser system.● Increasing diameter will also lead to a reduction in gas superficial velocity (Usg).● The flow will tend to be stratified, except when the superficial velocity gas, liquid flow conditions

and pipeline-riser inclination are suitable to cause coalesce of roll waves and give rise to slug flow● Increasing depth will lead to increase in hydrostatic pressure.● Also, it is important to note that increasing depth at lower wellhead flowing pressure will lead to

increased pressure fluctuation along the pipeline-riser system, with tendency for slug formation.● Development of a flow regime map with a sample deepwater oil field case-study indicates

predominant transition to slug flow at 30% water-cut.● Increasing hydrostatic pressure with increasing water depth leads to larger flow instability.

References:1. Pickering, P., Hewitt, G., Watson, M. and Hale, C. (2001), The prediction of flows in production

risers-truth & myth, available at: http://www.feesa.co.uk/pdf/Discussion%20Papers/010627%20-%20Deepwater%20Risers%20Rev%20D.pdf (accessed 8th January 2013).

2. Doty, D. R. and Dutta-Roy, K. (1985), �Severe slugging in offshore pipeline riser-pipe systems�,.3. Bøe, A. (1981), �Severe slugging characteristics; part i: flow regime for severe slugging; part ii:

Point model simulation study�, Selected Topics in Two-Phase Flow, NTH, Trondheim, Norway,.4. Andritsos, N. and Hanratty, T. (1987), �Influence of interfacial waves in stratified gas-liquid

flows�, AIChE Journal, vol. 33, no. 3, pp. 444–454.5. Mandhane, J., Gregory, G. and Aziz, K. (1974), �A flow pattern map for gas—liquid flow in

horizontal pipes�, International Journal of Multiphase Flow, vol. 1, no. 4, pp. 537–553.

Figure 20—Flow Regime Transition Chart at RB (2712.72m) at 30% WC

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6. Barnea, D. (1987), �A unified model for predicting flow-pattern transitions for the whole range ofpipe inclinations�, International Journal of Multiphase Flow, vol. 13, no. 1, pp. 1–12.

7. Kadri, U., Mudde, R., Oliemans, R., Bonizzi, M. and Andreussi, P. (2009), �Prediction of thetransition from stratified to slug flow or roll-waves in gas-liquid horizontal pipes�, InternationalJournal of Multiphase Flow, vol. 35, no. 11, pp. 1001–1010.

8. Woods, B. D., Hurlburt, E. T. and Hanratty, T. J. (2000), �Mechanism of slug formation indownwardly inclined pipes�, International Journal of Multiphase Flow, vol. 26, no. 6, pp.977–998.

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Appendices

Appendix 1: Mass flowrates (M1 - M15) for Flow regime transition charts

S/N Mass-Flowrate Source 1 (Well X1) Source 2 (Well X2)

1 M1 Mgas � 1.25kg/sMoil � 1.45kg/sMwater � 2.80kg/s

Mgas � 1.53kg/sMoil � 3.53kg/sMwater � 2.53kg/s

2 M2 Mgas � 2.23 kg/sMoil � 2.77 kg/sMwater � 4.10 kg/s

Mgas � 2.42 kg/sMoil � 4.59 kg/sMwater � 3.42 kg/s

3 M3 Mgas � 3.21kg/sMoil � 4.10 kg/sMwater � 5.40 kg/s

Mgas � 3.31 kg/sMoil � 5.65 kg/sMwater � 4.31 kg/s

4 M4 Mgas � 4.19 kg/sMoil � 5.43 kg/sMwater � 6.70 kg/s

Mgas � 4.2 kg/sMoil � 6.71 kg/sMwater � 5.2 kg/s

5 M5 Mgas � 5.17 kg/sMoil � 6.76 kg/sMwater � 8.00 kg/s

Mgas � 5.29 kg/sMoil � 7.77 kg/sMwater � 6.39 kg/s

6 M6 Mgas � 6.15 kg/sMoil � 8.09 kg/sMwater � 9.30 kg/s

Mgas � 6.18 kg/sMoil � 8.83 kg/sMwater � 7.28 kg/s

7 M7 Mgas � 7.13 kg/sMoil � 9.40 kg/sMwater � 10.6 kg/s

Mgas � 7.07 kg/sMoil � 9.89 kg/sMwater � 8.17 kg/s

8 M8 Mgas � 8.11 kg/sMoil � 10.7 kg/sMwater � 11.9 kg/s

Mgas � 7.96 kg/sMoil �10.95 kg/sMwater � 9.06 kg/s

9 M9 Mgas � 9.10 kg/sMoil � 12.03 kg/sMwater � 13.2 kg/s

Mgas � 8.85 kg/sMoil � 12.01 kg/sMwater � 9.95 kg/s

10 M10 Mgas � 10.1 kg/sMoil � 13.36 kg/sMwater � 14.5 kg/s

Mgas � 9.74 kg/sMoil � 13.1 kg/sMwater � 10.85 kg/s

11 M11 Mgas � 11.08 kg/sMoil � 14.69 kg/sMwater � 15.8 kg/s

Mgas � 10.63 kg/sMoil � 14.20 kg/sMwater � 11.74 kg/s

12 M12 Mgas � 12.06 kg/sMoil � 16.02 kg/sMwater � 17.10 kg/s

Mgas � 11.52 kg/sMoil � 15.26 kg/sMwater � 12.63 kg/s

13 M13 Mgas � 13.04 kg/sMoil � 17.36 kg/sMwater � 18.4 kg/s

Mgas � 12.41 kg/sMoil � 16.66 kg/sMwater � 13.52 kg/s

14 M14 Mgas � 14.02 kg/sMoil � 18.69 kg/sMwater � 19.70 kg/s

Mgas � 13.30 kg/sMoil � 17.72 kg/sMwater � 14.41 kg/s

15 M15 Mgas � 15 kg/sMoil � 20.02 kg/sMwater � 21 kg/s

Mgas � 14.19 kg/sMoil � 18.78 kg/sMwater � 15.30 kg/s

18 IPTC-18546-MS

Appendix 2: Mass flowrates (M16 - M45) for Flow regime transition charts.

S/N Mass-Flowrate Source 1 (Well X1) Source 2 (Well X2)

1 M16 Mgas � 3.5kg/sMoil � 2.53kg/sMwater � 4.55kg/s

Mgas � 1.53kg/sMoil � 3.53kg/sMwater � 2.53kg/s

2 M17 Mgas � 5kg/sMoil � 4kg/sMwater � 8kg/s

Mgas � 2.5kg/sMoil � 5.45kg/sMwater � 4.25kg/s

3 M18 Mgas � 10kg/sMoil � 8kg/sMwater � 16kg/s

Mgas � 5kg/sMoil � 10.2kg/sMwater � 8.5kg/s

4 M19 Mgas � 25 kg/sMoil � 32 kg/sMwater � 42kg/s

Mgas � 15 kg/sMoil � 20.4kg/sMwater � 17kg/s

5 M20 Mgas � 25kg/sMoil � 20kg/sMwater � 25kg/s

Mgas � 28kg/sMoil � 25kg/sMwater � 30kg/s

6 M21 Mgas � 29kg/sMoil � 25kg/sMwater � 35kg/s

Mgas � 35kg/sMoil � 25kg/sMwater � 32kg/s

7 M22 Mgas � 40kg/sMoil � 26kg/sMwater � 38kg/s

Mgas � 42kg/sMoil � 27kg/sMwater � 30kg/s

8 M23 Mgas � 45kg/sMoil � 30kg/sMwater � 40kg/s

Mgas � 40kg/sMoil � 35kg/sMwater � 45kg/s

9 M24 Mgas � 55 kg/sMoil � 45 kg/sMwater � 38 kg/s

Mgas � 28 kg/sMoil � 25 kg/sMwater � 30 kg/s

10 M25 Mgas � 0.75kg/sMoil � 2.5kg/sMwater � 3.5kg/s

Mgas � 0.85 kg/sMoil � 1.55kg/sMwater � 2.55kg/s

11 M26 Mgas � 2.05kg/sMoil � 3.25kg/sMwater � 4.55kg/s

Mgas � 42 kg/sMoil � 45 kg/sMwater � 52 kg/s

12 M27 Mgas � 2.25kg/sMoil � 3.75kg/sMwater � 4.85kg/s

Mgas � 2.85 kg/sMoil � 3.95 kg/sMwater � 4.75 kg/s

13 M28 Mgas � 1.25kg/sMoil � 2.05 kg/sMwater � 2.95kg/s

Mgas � 1.45 kg/sMoil � 2.95 kg/sMwater � 3.85 kg/s

14 M29 Mgas � 5.00 kg/sMoil � 6.55 kg/sMwater � 7.50 kg/s

Mgas � 5.25 kg/sMoil � 6.55 kg/sMwater � 7.55 kg/s

15 M30 Mgas � 6.55 kg/sMoil � 7.55 kg/sMwater � 8.55 kg/s

Mgas � 6.75 kg/sMoil � 7.45 kg/sMwater � 8.55 kg/s

16 M31 Mgas � 6.25 kg/sMoil � 8.75 kg/sMwater � 9.55 kg/s

Mgas � 6.15 kg/sMoil � 9.55 kg/sMwater � 10.05 kg/s

17 M32 Mgas � 6.85 kg/sMoil � 9.75 kg/sMwater � 10.55 kg/s

Mgas � 6.35 kg/sMoil � 9.65 kg/sMwater � 11.05 kg/s

18 M33 Mgas � 6.85 kg/sMoil � 9.75 kg/sMwater � 10.55 kg/s

Mgas � 6.35 kg/sMoil � 9.65 kg/sMwater � 11.05 kg/s

19 M34 Mgas � 1.05 kg/sMoil � 2 kg/sMwater � 1.58 kg/s

Mgas � 35 kg/sMoil � 25 kg/sMwater � 32 kg/s

continued on next page.

IPTC-18546-MS 19

List of Abbreviation

BoPD Barrel of Oil Per DayCAPEX CAPital EXpenditureFEED Front End Engineering DesignFPSO Floating Production Storage and OffloadingGOR Gas Oil RatioGUI Graphical User InterfaceID Internal DiameterIN INletKH Kelvin HelmhotzMF ManifoldMMScf/d Million Standard cubic feet per dayNSLUG Number of SlugOLGA OiL and GAsOPEX Operational EXpenditurePT Pressure readingPTDF Petroleum Technology Development FundPVT Pressure Volume TemperatureRB Riser-Base

Appendix 2 (Continued)—Mass flowrates (M16 - M45) for Flow regime transition charts.

S/N Mass-Flowrate Source 1 (Well X1) Source 2 (Well X2)

20 M35 Mgas � 25 kg/sMoil � 22 kg/sMwater � 32 kg/s

Mgas � 15 kg/sMoil � 18 kg/sMwater � 20 kg/s

21 M36 Mgas � 3.58 kg/sMoil � 11.05 kg/sMwater � 11.25kg/s

Mgas � 3.65 kg/sMoil � 11.55 kg/sMwater � 12.25 kg/s

22 M37 Mgas � 4.58 kg/sMoil � 11.65 kg/sMwater � 12.45kg/s

Mgas � 3.65 kg/sMoil � 11.55 kg/sMwater � 12.65 kg/s

23 Mgas � 5.58 kg/s Mgas � 5.65 kg/s

M38 Moil � 11.85 kg/sMwater � 12.75kg/s

Moil � 14.55 kg/sMwater � 15.65 kg/s

24 M39 Mgas � 7.58 kg/sMoil � 15.85 kg/sMwater � 13.25kg/s

Mgas � 7.65 kg/sMoil � 15.75 kg/sMwater � 18.65 kg/s

25 M40 Mgas � 8.58 kg/sMoil � 17.85 kg/sMwater � 15.25kg/s

Mgas � 8.65 kg/sMoil � 17.75 kg/sMwater � 19.65 kg/s

26 M41 Mgas � 8.58 kg/sMoil � 17.85 kg/sMwater � 15.25kg/s

Mgas � 8.65 kg/sMoil � 17.75 kg/sMwater � 19.65 kg/s

27 M42 Mgas � 9.58 kg/sMoil � 18.85 kg/sMwater � 20.25kg/s

Mgas � 9.85 kg/sMoil � 19.75 kg/sMwater � 20.75 kg/s

28 M43 Mgas � 10.58 kg/sMoil � 19.85 kg/sMwater � 21.25kg/s

Mgas � 11.85 kg/sMoil � 20.85 kg/sMwater � 21.75 kg/s

29 M44 Mgas � 12.58 kg/sMoil � 20.85 kg/sMwater � 22.25 kg/s

Mgas � 13.85 kg/sMoil � 21.85 kg/sMwater � 22.75 kg/s

30 M45 Mgas � 14.58 kg/sMoil � 22.85 kg/sMwater � 23.25kg/s

Mgas � 15.85 kg/sMoil � 24.85 kg/sMwater � 25.75kg/s

20 IPTC-18546-MS

RBGL Riser Base Gas LiftSTB/d Stock Tank Barrel per daySTP Standard Temperature PressureTM Temperature readingTP ToPsidesVKH Viscous Kelvin-HelmhotzVLW Viscous Long WavelengthWC Water-CutWH WellHead

IPTC-18546-MS 21