minimizing interference between top tension risers for tension … · 2020. 5. 21. · dril-quip,...

MINIMIZING INTERFERENCE BETWEEN TOP TENSION RISERS FOR TENSION LEG PLATFORMS

Ryan Koska 2H Offshore Engineering Pty. Ltd.

Perth, WA, Australia

Jim Kaculi Dril-Quip, Inc.

Houston, TX, USA

Mike Campbell 2H Offshore Inc.

Houston, TX, USA

Darren Mills Dril-Quip, Inc.

Houston, TX, USA

ABSTRACT Interference between TTRs is a key design challenge. For

spars, this is typically mitigated by having a large spacing

between wellheads, thus increasing the distance between risers

along the water depth. However, due to lower TTR tensioner

stroke limits combined with larger vessel offsets, the feasibility

of spacing out the wellheads for TTRs on a TLP is limited. The

result is TTRs that are closer together through depth and

therefore more likely to contact each other in extreme current

conditions.

This paper presents the approach used to minimize the

interference between the top tension risers on TLPs. Specific

topics include considering current profiles with varying

directions through the water depth, adjusting the top tension of

the risers, and utilizing low-drag vortex-induced vibration

(VIV) suppression strakes. The relative effect of each of these

topics is also discussed.

INTRODUCTION Top tension risers on TLPs are typically within close

proximity to each other, as shown by the example wellbay and

nominal seafloor layout in Figure 1. Typical center-to-center

spacing between adjacent wellbays is 5-6m and the minimum

nominal spacing between adjacent wellheads is usually less than

10m. The proximity of risers, combined with stroke and vessel

payload limitations makes mitigating potential interference

between risers challenging.

In recent years, there has been a trend to include drilling

capabilities to production vessels. This allows the operator to

bring production online with a few pre-drilled wells and then

drill and complete the rest of the field using the production

vessel. The revenue from the initial production help the

operator start to recover the up-front capital costs more quickly

and eliminating the need for a separate drilling vessel reduces

the overall cost to develop the field. However, this can further

complicate riser interference by adding a drilling riser with a

different diameter and top tension factor from the production

risers.

In addition, at the detailed design phase of projects, the hull

design, resulting payload limitations and deck heights and

stroke limits are often fixed. This limits the ability to optimize

the riser configurations to improve riser to riser interference.

Figure 1 – Example Wellbay and Seafloor Layout

Proceedings of the ASME 2013 32nd International Conference on Ocean, Offshore and Arctic Engineering OMAE2013

June 9-14, 2013, Nantes, France

OMAE2013-11182

1 Copyright © 2013 by ASMELearn more at www.2hoffshore.com

TOP TENSIONED RISER DESCRIPTION Typical configurations of the production and drilling risers

are shown in Figure 2. The production risers on TLP are usually

dry tree systems and the drilling riser are high pressure systems

with a surface BOP.

Production risers on TLPs typically have a steel outer

diameter of 12-16 inches (304.8–406.4mm) with 1-3 inches

(25.4-76.2mm) of external insulation. For this paper, an outer

diameter of 14 inches (355.6mm) with 2 inch (50.8mm) thick

external insulation is considered. VIV suppression strakes are

typically present on the majority of the riser length. The most

common strake drag coefficient is 1.6, leading to increased riser

deflections under current loading and therefore, increased

likelihood of clashing between risers.

Drilling risers on production vessels can have the same

pipe size as the production riser or can be full size risers with

outer diameters of about 21 inches (508mm). Buoyancy

modules can be used in order to reduce the tension requirements

for the riser. For this paper, a full size 20 inch diameter riser is

considered with buoyancy modules present on about half of the

riser’s length. The buoyancy modules have an outer diameter of

46 inches (1.17m). Most of the remaining riser length has VIV

suppression strakes, as shown in Figure 2. The large diameter of

the buoyancy modules, combined with the presence of strakes

on the rest of the riser can lead to high drag loading on the riser,

thus increasing the probability of interference between it and

adjacent production risers.

Figure 2 – Example TLP Production and Drilling Riser

Configurations

CURRENT LOADING Currents in the regions in which TLP are either already

present or are currently being design can be quite onerous, with

the 100 year surface current speeds ranging from 2.1 to 2.7

knots (1.1 to 1.4 m/s). Example 100 year current profiles are

shown in Figure 3.

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100 YEAR EXTREME CURRENT PROFILES1000m Water Depth, Locations with TLPs

Gulf of Mexico Australia (North West Shelf) Brazil

Figure 3 – Example 100 Year Extreme Current Profiles

INTERFERENCE ANALYSIS APPROACH

Interference analysis is conducted using the non-linear,

time-domain analysis software FLEXCOM, [1]. Wake effects

are implemented in FLEXCOM using the wake theory

developed by Huse, [2], in accordance with API RP 2RD, [3].

The wake from the upstream riser reduces the current velocity

acting on the downstream riser, as shown in Figure 4. The

reduced velocity decreases the deflection of the downstream

riser, therefore increasing the likelihood of interference between

the risers.

Both risers are susceptible to VIV excitation due to the fact

that neither is fully straked. VIV fatigue analysis is conducted

for both risers in order to determine the drag amplification due

to VIV. In order to remain conservative, the VIV drag

amplification is applied to the upstream riser, but not to the

downstream riser.

Static analysis with the vessel offset and current loading is

used to evaluate each of the selected riser pairs and

environmental loading directions. The minimum riser clearance

is extracted for each load case in order to determine if clashing

between risers occurs. Contact between risers is typically not


allowed for operating and extreme environments. Depending on

operator requirements, contact between risers can be allowed

during survival conditions. As per API RP 2RD, contact can

only be allowed provided that subsequent analysis shows that

the contact does not threaten the integrity of either riser, [3].

Figure 4 – Wake Profile Behind and Cylinder in Stationary

Flow, [2]

RISER INTERFERENCE CHALLENGES

A number of factors contribute to the potential for clashing

between adjacent risers. These include items such as the

presence of VIV suppression strakes, riser splay limitations and

vessel payload capacity.

Riser Splay Limitations An effective method of mitigating interference between top

tension risers is to increase the spacing of the wellheads. This

increases the distance between adjacent risers through the water

column and reduces the likelihood of clashing. However, there

are several consequences of increasing wellhead spacing that

must be considered.

By increasing the wellhead spacing, the riser splay, which

is the lateral distance between the wellhead and wellbay, must

also increase. This results in higher bending moments in the

tieback connector at the base of the riser for vessel offsets

opposite to the riser direction of splay (i.e. - a far offset). The

riser splay, and therefore the wellhead spacing, must be small

enough so that the tieback connector bending moment capacity

is kept within acceptable limits during extreme storm events.

Another consequence of increasing the riser splay is that

the riser stroke also increases. An example of this is shown in

Figure 5. For a 120m TLP offset away from the direction of

riser splay with associated set-down, the riser stroke due to

vessel offset alone increases from 31 inches (0.79m) to 52

inches (1.32m) with an increase in splay from 6.5m to 13.5m.

The total riser stroke range is increased due to environmental

loading, dynamic vessel response, tidal variations, thermal and

pressure loading from internal fluids, and changes in weight due

to variation in contents. These factors can add several feet to the

overall stroke range of the riser. TLP tensioners typically have a

stroke capacity of less than 10 feet (3m), making stroke a key

design parameter. The riser splay, and therefore the wellhead

spacing, must be small enough so that the tensioner stroke range

is not exceeded.

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PRODUCTION TTR STROKE VS SPLAYNo Environmental Loading; 120m TLP Offset; 6.0m TLP Setdown

Figure 5 – Riser Stroke vs. Splay

Vessel Payload Limitations The riser deflections due to current loading, and therefore

the likelihood of interference between risers, can be reduced by

increasing the riser top tension, as shown in Figure 6. However,

due to the potential for a large number of risers combined with

the limited payload capacity of TLPs, there is typically little

margin for increasing the tension in the risers. This is

particularly the case during the detailed design phase of work,

when the vessel payload capacity is essentially fixed.

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EFFECT OF TOP TENSION ON RISER DEFLECTION100 Year Current, No Vessel Offset or Wave Loading

TTF = 1.7 TTF=2.0 TTF=2.4 Figure 6 – Riser Deflection for Range of Top Tension

Factors


INTERFERENCE MITIGATION METHODS FOR TLPS Several mitigation methods can be utilized TLP TTRs in

order to overcome the challenges presented above and achieve

acceptable riser clearance. These methods include considering

the change in current direction through depth, the use of low

drag VIV suppression strakes, and optimizing the tension of the

risers.

Consideration of Current Direction through Depth In order to be conservative, interference analysis is often

conducted considering unidirectional current profiles. This

maximizes the wake effects on the downstream riser, therefore

increasing the likelihood of interference between the risers.

However, current profiles typically have variations in

direction through depth. Considering directionality of the

current profiles through depth can reduce any unnecessary

conservatism of the interference analysis. The portion of the

current profile out of the plane of the two risers reduces the

length of the downstream riser that is in the wake field of the

upstream riser, therefore reducing the probability of

interference. An example of riser clashing that is mitigated by

considering multidirectional currents is shown in Figure 7 and

Figure 8.

This approach to reduce conservatism can be utilized

provided that sufficient current measurements have been taken

in order to determine the predominant current directions

through depth. An example of this would be a location that has

a predominant surface current direction due to ocean circulation

and a different principal bottom current direction due to

bathymetric characteristics, such as an escarpment. Variations in

the current direction, both at the surface and through depth

should be accounted for in order to ensure that the most onerous

case is captured.

Figure 7 – Example of Riser Clashing with Unidirectional

Current Profile

Figure 8 – Example of Riser Clearance Achieved using

Multidirectional Current Profile


Utilizing Low Drag VIV Suppression Strakes The most common drag coefficient for the VIV suppression

strakes used on the production and drilling risers is 1.6.

However, vendor published test data is available showing that

strakes can be manufactured that have a drag coefficient of

about 1.4 while maintaining VIV suppression efficiency of

greater than 90%. The selection of low-drag strakes for use on

the production riser supported by available test data allows for

the use of a reduced drag coefficient in the interference

analysis.

The effect of strake drag coefficient on production riser

deflections with 100 year current loading with no vessel offset

is shown in Figure 9. Deflections for the riser without strakes

are also shown for comparison. Utilizing low drag strakes

reduces the maximum deflection of the riser from 14m to

12.5m. Low drag strakes can be specified in addition to the

consideration of multi-directional current profiles to greatly

improve clearance between adjacent risers of the same type and

top tension.

The use of low drag strakes can have a negative effect on

first and second order fatigue due to the reduced hydrodynamic

damping acting on the riser. Higher levels of vessel motions are

allowed to propagate along the riser’s length, resulting in more

fatigue loading. Analysis should be conducted to confirm that

the riser has adequate fatigue performance with low drag

strakes.

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EFFECT OF STRAKE DRAG COEFFICIENT ON RISER DEFLECTION

100 Year Current, No Vessel Offset or Wave Loading

No Strakes Strake Cd = 1.4 Strake Cd = 1.6

Figure 9 – Riser Deflections for Range of Commercially

Available Strake Drag Coefficients

Optimizing Drilling Riser Top Tension Unlike the production riser, the majority of the drilling riser

is unstraked. This causes lower deflections for the drilling riser

for the same current loading and leads to interference when the

production riser is upstream of the drilling riser. Therefore,

larger drilling riser deflections are required in order to mitigate

interference with the production risers. It is generally

undesirable to add strakes to the buoyant joints on the drilling

riser as this increases the complexity and time required for riser

installation and retrieval.

In order to increase the deflection of the drilling riser and

mitigate interference with the production risers, the top tension

factor, defined as the top tension applied divided by the weight

of the riser, is reduced from 1.75 to about 1.5. This reduction in

top tension effectively mitigates the interference when the

production riser is upstream, while keeping the drilling riser

deflection low enough so that clearance is maintained when the

production riser is downstream. An example of the interference

between production and drilling risers being mitigated by

reducing the drilling riser tension is shown in Figure 10.

Reducing the riser top tension typically results in a

reduction in fatigue lives, particularly due to VIV. Analysis

should be conducted to confirm adequate fatigue performance

with the reduced tension.

Figure 10 – Example of Interference between Production

and Drilling Riser Mitigated by Reducing Drilling Riser

Top Tension

Drilling Riser TTF = 1.75

Drilling Riser TTF = 1.5


CONCLUSIONS Due to the close spacing between risers as well as limited

vessel payload and riser stroke capacities, interference between

risers is a key design challenge for top tension risers on tension

leg platforms. Addressing riser interference to a detailed level

as early as possible, preferably during FEED, is recommended

as changes to riser tension or stroke limits can be made during

this phase.

Three mitigation techniques can be utilized in order to

minimize the potential for clashing between the production and

drilling risers on TLPs. These mitigation methods include

considering multi-directional currents through depth, utilizing

low drag strakes on the production risers and optimizing the top

tension of the drilling riser. Using one or more of these methods

in combination can successfully mitigate interference between

top tension risers on a TLP.

NOMENCLATURE TLP Tension Leg Platform

TTF Top Tension Factor

TTR Top Tension Riser

VIV Vortex Induced Vibration

REFERENCES

[1] Marine Computational Services (MCS) –

“FLEXCOM-3D Three-Dimensional Nonlinear Time

Domain Offshore Analysis Software.” Version 7.9.4,

2009

[2] Huse, E., “Experimental Investigation of Deep Sea

Riser Interaction,” Paper No. 8070, Offshore

Technology Conference, Houston, May 1996.

[3] American Petroleum Institute (API), “Design of

Risers for Floating Production Systems (FPSs) and

Tension-Leg Platforms (TLPs)”, API Recommended

Practice 2 RD, First Edition, June 1998, Reaffirmed

May 2006.


minimizing interference between top tension risers for tension … · 2020. 5. 21. · dril-quip,...

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