Control difuso por parte de la administración tributaria

0

Riser Gas Lift (MMSCFD)

0.1 1

0.01

Froude#

FR < 0(1): Riser instability and possible slugging

Figure 1.17 – Influence of Riser Gas lift on Riser Froude Number, as a Means to Eliminate Riser Instability and Terrain Slugging Shown for the 12in East-side Risers

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D Page 35 of 89 30-April-2006

OPRM20030302D_014.ai

10 20 30 40

0

Liquid Production Rate (MBLPD)

10

5 15 20

0

Required Gas Lift (MMSCFD)

0%wc 50%wc 80%wc

Figure 1.18 – Riser Base Gas Lift Required for Complete Suppression of Terrain Slugging for 10in West-side Flowlines

OPRM20030302D_015.ai

10 20 30 40

0

Liquid Production Rate (MBLPD)

20

10 30 40

0

Required Gas Lift (MMSCFD)

0%wc 50%wc 80%wc

Figure 1.19 – Riser Base Gas Lift Required for Complete Suppression of Terrain Slugging for 10in East-side Flowlines

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D Page 36 of 89 30-April-2006

OPRM20030302D_016.ai 10 20 0%wc 50%wc 80%wc 30 40 0

Liquid Production Rate (MBLPD)

10 20 30

0

Required Gas Lift (MMSCFD)

Figure 1.20 – Riser Base Gas Lift Required to Limit Terrain Slugging to Within 50bbl Slugs for 12in East-side Flowlines

OPRM20030302D_017.ai 5 10 10MBLPD 20MBLPD 40MBLPD 15 20 25 0

Gas Lift Rate (MMSCFD)

400 200 600 800 0 Maximum Slug V olume (bbl)

Figure 1.21 – Slug Volumes Calculated for 12in East-side Flowlines and 50% Water Cut as a Function of Gas Lift Rate

Section 1 Dynamic Flow Assurance Analysis

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OPRM20030302D_018.ai 5 10 10MBLPD 20MBLPD 40MBLPD 15 20 25 0

Gas Lift Rate (MMSCFD)

10

5 15 20

0

Maximum Separator Level Fluctuation (%)

Figure 1.22 – Separator Level Fluctuation Calculated for 12in East-side Flowlines and 50% Water Cut as a Function of Gas Lift Rate

OPRM20030302D_019.ai Horizontal Length (m) 0 1000 2000 3000 4000 5000 6000 7000 60 70 80 90 100 110 120 130 ºF

Figure 1.23 – Effect of Cold (40°F) Gas Lift Injection on Arrival Temperature for 10MBOPD Production and 25MMSCFD Gas Lift for Slug Suppression

Section 1 Dynamic Flow Assurance Analysis

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OPRM20030302D_020.ai

5 10 15 20 25

0

Effective U of Each Umbilical Tube (W/m^2-C)

50 30 40 70 60 80 20 Gas Injection T emperature (ºF) Tin = 120ºF Tin = 140ºF

Figure 1.24 – Gas Injection Temperatures at Mudline for Prior Umbilical-based Gas Lift Design

OPRM20030302D_021.ai

2.5 3 3.5 4 4.5 5

2

Gas Lift Tube ID (in)

105 115 110 120 100 Gas Injection T emperature (ºF)

Figure 1.25 – Dependence of Gas Injection Temperature on Gas Lift Riser Diameter

Section 1 Dynamic Flow Assurance Analysis

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OPRM20030302D_022.ai 3 4 5 6 7 8 2 Effective U (W/m^2-C) 85 75 80 95 90 100 70 Gas Injection T emperature (ºF)

Figure 1.26 – Dependence of Gas Injection Temperature on Gas Lift Riser Insulating Value for a 3.5in Tube Diameter

Section 1 Dynamic Flow Assurance Analysis

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OPRM20030302D_023.ai

5 10

Heater T (ºF) Heater T

Production Riser

Gas Lift Riser 3.5in ID UID = 4W/m2-C Topsides Subsea Riser Inlet T Injection T From Gas Heater

Riser Inlet T (ºF) Injection T (ºF) 15 20 25 30 0 Gas Rate (MMSCFD) 200 180 160 140 120 100 220 80 Gas Injection T emperature (ºF) Spec = 90ºF

Figure 1.27 – System Temperature Summary for Base-case Flexible Riser-based Gas Lift Design

Section 1 Dynamic Flow Assurance Analysis

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5.0 SUBSEA SYSTEM SHUTDOWN: HYDRATE PREVENTION STRATEGIES

A critical aspect of hydrate management for deepwater subsea systems is prevention of hydrate formation by system cooling during shut-ins of widely varying duration. Operationally, subsea shut-ins are inherently complex with multiple decision gates (particularly for a subsea network of the scope of Bonga), with operating procedures which depend on the shutdown duration.

5.1 Cooldown Performance of Subsea Facilities

To aid Operations staff, who must simultaneously work to troubleshoot the shutdown and to protect the subsea system from hydrates, subsea facilities must be designed with sufficient cooldown time. In general terms, cooldown is defined as the time required for the inner wall of the flowpath to reach the hydrate formation temperature, somewhere in the system. The contributions to the cooldown time anticipated for Bonga (refer to Figure 1.28) consist of:

• ‘No-touch’ time

• Time to treat the well tubing and wellhead equipment • Time allotted for flowline blowdown

The no-touch time is defined as the time during which Operations staff can act to rectify the shutdown cause, without having to undertake operations to protect the subsea system from hydrates. The 3-hour no-touch time specified for Bonga is based on GoM platform statistics for unplanned shutdowns (refer to Figure 1.29), which indicate that 80% of typical process and instrumentation interrupts were analysed and corrected within 3 hours. Figure 1.29 indicates a rapidly diminishing benefit of no-touch times longer than 3 hours.

5.1.1 Well Tubing

Based on the timing illustrated in Figure 1.28, the well tubing must provide at least 8 hours of cooldown time, accounting for a well MeOH treatment time of 5 hours (ie well tubing cooldown time > 3-hour no-touch + 5-hour MeOH well treatment). An important benefit of bare well tubing is the lengthy wellbore cooldown provided by thermal energy generated in the surrounding formation during (steady-state) production. As shown in Figure 1.30, for early-life production at minimum rate (10MBOPD), at least 48 hours of cooldown are available in the wellbore (eg 100ft depth and below). Thus, MeOH bullheading of the well to the SSSV will be required only for very lengthy shut-ins, ie greater than 2 days (expected to be rare). For shorter duration shut-ins, only the top portion of the wellbore (a few hundred feet) have to be topped with MeOH during the allotted 8-hour well cooldown time. For these shut-ins, less than 2 days will be required and they are expected to be much more frequent (refer to Figure 1.29). The required MeOH treatment time will generally be less than the 5 hours allotted. As an added benefit, this surplus time due to quicker MeOH treatment may be used to increase the no-touch time and/or the flowline blowdown time.

Section 1 Dynamic Flow Assurance Analysis

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5.1.2 Subsea Tree/Jumper/Manifold

As for the well tubing, the subsea tree, well jumper and manifold must provide at least 8 hours of cooldown, accounting for 5 hours allotted for MeOH displacement of these components. Although the chemical injection system is sized to treat all wells within 5 hours, 12 hours of cooldown time are specified for the wellhead facilities in the Subsea ITT as an added margin to assist Operations. In particular, the following gas cooldown specification appears in the Subsea Invitation to Tender (ITT).

• Upstream of choke (subsea tree)

– 120°F (49°C) to 73°F (23°C) in no less than 12 hours • Downstream of choke (subsea tree + well jumper + manifold)

– 120°F (49°C) to 63°F (17°C) in no less than 12 hours

The starting wellhead temperature of 120°F is satisfied for all initial-life wells at rates greater than 5MBOPD (refer to Figure 1.14). However, the field’s coldest well (702p7) does not reach 120°F at any rate and hence will require well-specific operating procedures. The final temperatures reflect the HDT at the well shut-in pressure (4600psia) upstream of the choke and the anticipated flowline shut-in pressure downstream of the choke.

5.1.3 Flowline and Riser

For both the pipe-in-pipe flowlines and steel catenary risers, a 12-hour cooldown is specified in the flowline/riser ITT, for gas-filled (methane) components at 28bara: • West-side 10in flowlines

– 97°F (36°C) to 66°F (19°C) in no less than 12 hours • East-side 10in and 12in flowlines

– 86°F (30°C) to 61°F (16°C) in no less than 12 hours

The work presented herein culminated in approval of MoC 59, which specifies that both this cooldown requirement and a U value requirement of Uod ≤ 2.0W/m2-C must

be met for the cylindrical cross-sections of the flowline and riser.

Note: The more conservative specification of gas cooldown is based on restart considerations, ie the hydrate risk of wet fluid passing through cold, originally gas-filled sections upon restart.

The starting temperatures for cooldown are based on the minimum anticipated riser base temperatures for 10MBOPD production, including margins for cooling by riser gas lift and possible reservoir cooling by waterflood. With these conservative margins, the starting riser base temperatures are comparable to the arrival temperatures at 10MBOPD (refer to Figure 1.15). The west-side starting temperature is 11°F than the east-side flowlines due to the significantly shorter offsets (hence lesser heat losses) of the west-side flowlines.

The final temperatures are based on the HDT at the flowline shut-in pressure, using the hydrate dissociation conditions of the 803 fluid with 0% salinity for conservatism. Furthermore, the effect of a 10-minute choke closure time on the flowline shut-in pressure is explicitly accounted for. Due to their longer offsets, the east-side flowlines experience less partial packing and hence a lower shut-in pressure, which is why the final temperature for east-side cooldown is lower (61°F for east-side versus 66°F for west-side).

Section 1 Dynamic Flow Assurance Analysis

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For the steel catenary risers, prior conceptual analysis (Granherne, 1998) had specified a 2in carazite insulation for (liquid-filled) cooldown. However, Figure 1.31(a) and 1.32(a) indicate that 2in of carazite does not satisfy the gas-filled cooldown requirement (typical for deepwater GoM), even at higher production rates. Figures 1.31(b) and 1.32(b) demonstrate that a 4in carazite (or equivalent) riser insulation is required to attain 12 hours of cooldown at the minimum turndown rate of 10MBOPD per flowline. The added benefit of a Ported Orifice Valve (POV) upstream of the choke is not accounted for, which will yield lower flowline shut-in pressures and hence longer cooldown times (ie results closer to the immediate choke closure curves in Figures 1.31 and 1.32). At anticipated production rates of 30 to 40MBOPD (according to the production function), 18 to 20 hours of gas cooldown are available, providing Operations staff additional time to react and/or secure the system against hydrates.

For the base-case pipe-in-pipe flowline design (refer to Figure 1.5), the U = 2.0W/m2-C requirement can be met by filling only 0.6in of the ~1in annular gap with polyurethane foam. However, the cooldown analysis presented here indicates that the annular gap must be filled with foam (at marginal additional cost) to meet the 12-hour gas cooldown requirement. In Figures 1.33 to 1.35, the cooldown performance of each pipe-in-pipe flowline is shown for 0.6in (U = 2.0W/m2-C) and 1in (foam-filled annulus) foam thicknesses. As summarised in Table 1.2, 10 to 11.5 hours of cooldown are attained with a 0.6in foam thickness. In each case, a foam-filled annular gap (with a 5mm tolerance for manufacturing) is required to meet the 12-hour gas cooldown specification.

In summary, this analysis reveals that the base case flowline with U = 2.0W/m2-C (without foam filling of the annular gap) does not satisfy the 12-hour cooldown requirement. The U value requirement is based only on steady-state thermal performance, which does not uniquely determine the cooldown performance. That is, significantly different cooldown performance can occur for the same U value, depending on the ‘thermal mass’ of the pipe and insulation system. As illustrated in Figure 1.36, a carrier pipe with a 0.94in wall thickness meets the 12-hour cooldown target, while a 0.75in wall provides only 10 hours of cooldown, although the corresponding U values are identical. The situation is complicated further for alternative pipe diameters and wall thicknesses, which may be explored in the detailed design process. Thus, to ensure adequate flowline/riser cooldown performance, MoC 59 specifies that both the U value and cooldown specifications shall be satisfied simultaneously.

East 12in East 10in West 10in

0.6in PU foam (U = 2W/m2-C)

11.5 hours 10.5 hours 10 hours 1in PU foam

(foam-filled gap)

13.5 hours 13 hours 12.5 hours

Table 1.2 – Cooldown Time as a Function of PU Foam Thickness Within ‘Pipe-in-pipe’ Flowlines

Section 1 Dynamic Flow Assurance Analysis

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In document Lima, 7 de julio de 2021 (página 114-117)