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The phenomenon of severe slugging induced by undulations in flowline terrain is predicted to be significant at Bonga in the absence of mitigating control, due to: • Significant downhill flow near the riser base for east-side flowlines

(~30m elevation drop, refer to Figure 1.49) • Production of high watercuts (80 to 90%) • Large diameter flowlines (10in to 12in) • Significant water depth (~1000m)

Note: The distinction between shorter hydrodynamic slugs (up to ~50 diameters in length) in locally horizontal or uphill flow and longer terrain slugs (proportional to the length of downhill flow), which are more problematic for topsides facilities and process control.

That terrain slugging is outside the scope of steady-state simulations, which cannot capture at all the adverse effects of higher well backpressure and order-of-magnitude fluctuations in liquid production rate. In the following, Olga2000 is used to define the terrain slugging operability envelope, including detailed assessment of slug suppression via riser gas lift.

For terrain slugging to occur in a flowline/riser system, three necessary conditions must be satisfied simultaneously (Vreenegoor, 1999):

(1) The Pots slugging number less than order unity in the flowline:

l g ss m m Lg zRT & & α = π < O(1)

(2) The densimetric Froude number less than order unity in the riser:

gD

U

Fr

)

(ρ

−ρ

ρ

=

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Physically, the slugging number condition:

• Reflects the fact that sufficient gas compressibility (‘capacitance’) is required for slugs not to be expelled from the flowline. The Froude number condition

• Indicates that unstable riser flow (ie liquid surging and fallback in the riser) is necessary to initiate a flow blockage at the riser base

• Enables growth of the liquid slug

For representative Bonga conditions at 10MBLPD and 50% watercut, the slugging numbers for each flowline are:

• East 12in: πss = 0.3

• East 10in: πss = 0.2

• West 10in: πss = 0.7

Furthermore, the Froude number (without gas lift) is on the order of 0.05 and stratified flow is predominant in the downhill flow regions near the riser base. Thus, based on this simple conceptual analysis, severe terrain slugging is predicted at Bonga without riser gas lift, particularly for the east-side flowlines.

Although it has not yet been field-proven for large-diameter deepwater risers, a potentially effective slug control technique involves gas injection at or near the riser base. With reference to the necessary conditions for terrain slugging, gas lift can eliminate the riser instability required for slug initiation (ie Froude number greater than order unity). For the 12in east Bonga flowline, riser gas lift increases the Froude number from order 0.05 to order 1 (refer to Figure 1.17), and hence is expected to be effective in slug suppression. In the following, Olga2000 computations are used to investigate in detail the effectiveness of riser gas lift in suppressing terrain slugging.

In Figures 1.18 to 1.20, the gas lift required to suppress terrain slugging is shown as a function of liquid production rate. In Olga2000, terrain slugging can be isolated from smaller, less problematic hydrodynamic slugs (ie by switching Slugtracking off), to yield a sharp transition from terrain to hydrodynamic slugging. For all west-side 10in flowlines (refer to Figure 1.18), no riser gas lift is required at the minimum turndown rate of 10MBLPD, even at 80% watercut. This result is in contrast to prior studies (Granherne, 1998), which indicated that 5MMscfd gas lift was required, apparently due to inaccurate modelling of the riser-base topography.

Note: Slugging may be suppressed at turndown rates as low as 5MBLPD, by gas lift rates up to 10MMscfd (refer to Figure 1.18).

For the 10in east-side flowlines, 5 to 10MMscfd gas lift is required to eliminate slugging for the minimum rate of 10MBLPD at 0 to 80% watercut (refer to Figure 1.19). Due to the more adverse east-side topography, the gas lift requirement for flowrates lower than 10MBLPD is much more significant for the 10in east flowlines, compared to the 10in west results. Thus, even at the gas lift capacity of 25MMscfd per flowline, signficant slugging will occur for the east-side flowlines for turndown rates lower than approximately 8MBLPD (refer to Figure 1.19).

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For the 12in east flowlines, terrain slugging cannot be totally eliminated by feasible riser gas lift rates. Hence, for these 12in flowlines, the gas lift required to reduce the terrain slug size to <50bbl is shown in Figure 1.20. Due to the larger diameter, the gas lift requirements are more stringent compared to the 10in east-side results. In particular, gas lift approaching 20MMscfd is required at the minimum rate of 10MBLPD and 80% watercut (refer to Figure 1.20). In addition, marginal gas lift volumes are needed at higher production rates as well (eg ~5MMscfd at 20MBLPD), suggesting that gas lift (albeit at varying rates) may be frequently required for the 12in east flowlines, even very early in field life. The required gas lift volumes at the minimum anticipated turndown rate of 10MBLPD are summarised for all flowlines in Table 1.1. Flowline Watercut Minimum Stable Production Without Gas Lift Gas Lift Required for 10MBLPD Production 10in West PFL 8/9 PFL 11/12 0% 50% 80% 10MBLPD 10MBLPD 10MBLPD 0 0 0 10in East PFL 1/2 0% 50% 80% 30MBLPD 35MBLPD 35MBLPD 5MMscfd 8MMscfd 10MMscfd 12in East PFL 3/4/5/6 0% 50% 80% 30MBLPD 35MBLPD 40MBLPD 10MMscfd 17MMscfd 17MMscfd

Note: The requirements for the 12in east flowline are based on a maximum slug volume of 50bbl, while results for other flowlines reflect complete terrain slug suppression.

Table 1.1 – Riser Gas Lift Requirements for Terrain Slug Suppression

To address severe slugging and the mitigating effect of riser gas lift in greater detail, an Olga Slugtracking Analysis was performed for the 12in east flowline, which exhibits the worst-case slugging (refer to Table 1.1). The Olga Slugtracking model captures the accumulation at the riser base of smaller hydrodynamic slugs generated in the flowline, which may enhance terrain slugging. Additionally, the effect of slugging on topsides vessel level control is modelled as an inlet separator attached to the flowline outlet, with the following specifications (in accord with the Bonga topsides conceptual design):

• 132in diameter x 50ft seam-seam inlet separator (reflecting one of two available separators)

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• Oil dump valve Proportional Integral Derivative (PID) controller: – Gain = 10

– Integral const = 60 s (fast-acting level control)

For the 12in east flowline at 50% watercut, significant slug volumes on the order of 800bbl are predicted at turndown rates of 10 to 20MBLPD in the absence of riser gas lift (refer to Figure 1.21). As a consequence of these large slug volumes (without gas lift), separator level fluctuations of 10 to 20% occur at 10 to 20MBLPD (refer to Figure 1.22), magnitudes considered by Bonga topsides engineers to be unacceptably large for efficient separation and overall process control. Riser gas lift is seen to be particularly effective in reducing the slug volume, as manageable slug volumes of 50 to 100bbl and separator level fluctuations of 2 to 3% are attained with only 10MMscfd gas lift (Figures 1.21 and 1.22).

Note: There is no benefit of gas lift rates higher than 10MMscfd, due to smaller (~50bbl) hydrodynamic slugs generated in the flowline and accelerated through the riser.

In summary, modest gas lift rates on the order of 10MMscfd per flowline are predicted to manage severe slugging at Bonga to an acceptable degree, for a minimum turndown rate of 10MBLPD. Nevertheless, it is important to apply a significant design margin to these results, noting the modelling complexity and lack of field data for riser gas lift in deepwater systems. In particular, further experimental studies are clearly needed for gas lift in large-diameter risers, to confirm the effectiveness of gas lift in lifting riser liquid during flowing conditions (ie extending recent experimental analysis of gas lifting of a static liquid column; Zabaras and Schoppa, 2001). Additionally, the ‘resonance’ of multiphase flow in the flowline with topsides process flows (shown to intensify severe slugging in recent industry publications) is a detailed design issue beyond the scope of this report. Such coupling of subsea/topsides flows is the subject of extensive ongoing dynamic simulation work for Bonga (Duhon and Schoppa, 2001).