TECHNICAL PAPER - 2H Offshore€¦ · towards High Pressure High Temperature (HPHT) wells. The challenges due to HPHT wells are similar to the ultra-deepwater challenges in that the

TECHNICAL PAPER

Vessel Interface Considerations

for Ultra Deepwater

Intervention Risers

R. Vaidya, M. Sonawane, E. Whiteley (2H), J. Rourke (Helix)

OMAE June 2019

1 Copyright © 2019 by ASME

Proceedings of the 38th International Conference on Ocean, Offshore & Arctic Engineering

OMAE19 June 9-14, 2019, Glasgow, Scotland

OMAE2019-95519

VESSEL INTERFACE CONSIDERATIONS FOR ULTRA DEEPWATER INTERVENTION RISERS

Rohit Vaidya 2H Offshore

Houston, TX, USA

Mahesh Sonawane 2H Offshore

Houston, TX, USA

Benjamin Toleman

2H Offshore Houston, TX, USA

Elaine Whiteley 2H Offshore

Aberdeen, UK

Jonathan Rourke Helix ESG

Houston, TX, USA

ABSTRACT For ultra-deepwater subsea wells, a riser system is required to

conduct completion, intervention/workover and end of life

activities. For ultra-deepwater riser systems with high

temperature and pressure requirements, the intervention riser

system often requires vessel interface optimization to achieve acceptable design response. The upper riser can be configured in

several different ways, each with its own benefit from a safety,

risk and performance perspective. This paper compares the riser

response for various vessel interfaces for ultra-deepwater

applications.

As discussed above, intervention riser structural response is

sensitive to the riser configuration at the vessel interface. For a

typical intervention riser, due to ultra-deepwater and high tension

requirements, the functional tension load may utilize up to 40%

of yield strength thus decreasing the capacity available to

accommodate bending and pressure loads. Vessel operators have options to modify the system configuration to improve the

strength and fatigue response of the riser. The different vessel

interface options include the tension lift frame (TLF) to vessel

interface, the top tension application method and the use or

otherwise of a surface tree dolly. Upper riser assembly (URA)

loads may be optimized by use of rotary wear bushings, a cased

wear joint assembly or flexjoints as a part of the stack-up.

The various riser-vessel interface options are evaluated and

compared in this paper. This paper highlights the riser design

challenges for ultra-deepwater applications.

NOMENCLATURE API American Petroleum Institute

CT Coiled Tubing

CWJ Cased Wear Joint

DSC Drill String Compensator

EDP Emergency Disconnect Package

HPHT High Pressure High Temperature

ID Inner Diameter ISO International Standard Organization

LRP Lower Riser Package

OD Outer Diameter

RAO Response Amplitude Operators

RP Recommended Practice

SFT Surface Flow Tree

THRT Tubing Hanger Running Tool

THS Tubing Head Spool

TLF Tension Lift Frame

TRT Tree Running Tool

TSJ Tapered Stress Joint

URA Upper Riser Assembly USJ Upper Stress Joint

INTRODUCTION Intervention operations are performed to increase the

productivity of wells, which is typically required towards their

end of life. Completion operations are a step that is required to

bring the well from a successfully drilled well to production

phase. Intervention and completion operations can be performed

either in closed water mode, in which a landing string/

completion riser is installed through a drilling riser or open water

mode, where the completion riser is installed in open water. In a low oil price environment, most operators are focused on

performing intervention operations to enhance the productivity

Learn more at www.2hoffshore.com


of older wells as it is significantly more cost effective compared

to drilling new wells.

To perform intervention/completion operations in open water

mode, a riser system is required from the subsea well to the rig floor and a large surface equipment stack is required above the

rig floor. Intervention riser system integrity needs to be

established for both strength and fatigue performance. The upper

riser configuration and its vessel interface can play a key role in

determining the riser system performance. Upper riser

assemblies (URAs) can be configured in a number of different

ways, and each of them have their own advantages and

disadvantages. In some cases, the options in which the URA can

be configured is restricted because of vessel construction/

spacing, but in most cases it can be optimized, especially for rigs

under construction and purpose built intervention rigs. This

paper compares the riser response for a range of vessel interfaces and upper riser assemblies to show the benefits and trade-offs of

these configurations. The primary focus is the comparison of the

strength response between configurations.

BACKGROUND

RISER CONFIGURATION AND DESIGN CRITERIA A typical intervention riser subsea stack consists of a Tree

Running Tool/ Tubing Hanger Running Tool (TRT/THRT),

Lower Riser Package (LRP) and an Emergency Disconnect

Package (EDP). The riser pipe typically ranges from 5 inch to 7 5/8” drill pipe and includes multiple crossover joints and

specialty joints like Tapered Stress Joints (TSJs) and tension

joints. The surface equipment includes the surface flow tree, the

elevator sub, the TLF, coil tubing and other ancillary equipment

depending on the type of operation. A typical intervention

configuration is shown in FIGURE 1. Intervention risers are

designed as per API RP 17G (American Petroleum Institute

Recommended Practice) or ISO (International Standard

Organization) 13628-7 codes. Primary design parameters for

determining intervention riser performance are:

• Riser pipe stresses (ISO utilizations)

• Clearance with moonpool and clearance of the Surface Flow

Tree (SFT) with the drill floor

• Compensator stroke limit

• Connector bending and tension capacities

• EDP disconnect angle limit

Both strength and fatigue performance depend on the strength of

the riser system, the environmental loads, the pressure and

temperature of wells, vessel characteristics (Response

Amplitude Operators (RAO’s)) and the upper riser and vessel interface.

FIGURE 1 – TYPICAL INTERVENTION RISER

STACK-UP

DESIGN CHALLENGES Designing an intervention riser is challenging for several

reasons, including the following:

• Heavy surface equipment

• Response excitation • Complex non-linear dynamic response • Rigid annulus line and production line interaction • High bending moments in the upper riser assembly

• Same design has to work for multiple water depths

• Nonstandard design i.e. combination of equipment from rig contractor and operator

• Typically, fast track jobs (1-2) weeks that lack proper

planning

In addition to the design challenges faced above, the move

towards ultra-deepwater (>7,000ft) introduces additional

challenges. As the water depth increases the external pressure

increases. To design against collapse of the riser, the wall

thickness of the pipe needs to be increased. The additional wall

thickness of the pipe in combination with the increased length of

riser required results in a significant increase in the weight of the riser that causes increase in top tension. However, this results in

high axial stress in the top section of the riser. In ultra-deepwater

the tension in the upper section of the riser can be equivalent to

40% of the yield strength. This high tensile utilization essentially

reduces the capacity of the pipe to accommodate loads due to

bending and pressure. In addition, URA connector capacities will

further reduce due to increase in tension.

Riser Insert Bushing

Top Drive

Pipe Connectors

Top Bails

Tension Lift Frame

CT/WL Equipment

Elevator Sub

Surface Flow Tree

Swivel Assembly

Adapter

Upper X-Over Joint

Drill pipe

Lower X-Over Joint

Tapered Stress Joint

EDP

LRP

XTTHS

Drill Floor

Wellhead

Range ft

Top Tension

Pipe Connector

Transition Joint



Another challenging trend for intervention risers is the shift

towards High Pressure High Temperature (HPHT) wells. The

challenges due to HPHT wells are similar to the ultra-deepwater

challenges in that the top tension requirement increases which

utilizes a greater percentage of the allowable pipe capacity. To contain the high pressures within the pipe the wall thickness

needs to be increased relative to a non-HPHT riser design.

VESSEL INTERFACE DESIGN The vessel interface is critical in the design of an intervention

riser where there can be high loading in the URA due to heavy

weight of the riser in deep water.

The vessel motions under wave loading introduces dynamic

loading in the top riser section. The wave loading also acts

directly onto the riser which causes hydrodynamic loading in the

riser below the drill floor. Where and how the vessel interfaces with the riser can result in a significantly different response.

Depending on the vessel interface, high bending moment regions

can occur at the same location where the stress in the riser is

already high due to the considerable tension required, resulting

in a critical section in the systems design.

To a certain extent, the bending moment profile within the riser

system can be controlled by the location of lateral restraints. The

bending moment in the system is important as the limiting areas

of the design are often connector capacity limits or fatigue

performance.

By reviewing the proposed design and determining the critical

components in the specific system, the interaction of the vessel

with the riser system can be controlled to move the peak bending

away from the most critical areas and improve the performance

by varying the upper riser configuration.

UPPER RISER ASSMBLY CONFIGURATIONS A number of different upper riser configurations are used to

control the structural response of the system. These

configurations are shown in FIGURE 2 through FIGURE 5.

Different configurations include:

1. Top tension system with TLF laterally free and no

wear/rotary bushing at drill floor

2. Top tension system with riser frame laterally free and

wear bushing at drill floor

3. Using split tensioner system, TLF laterally free and no


4. Using split tensioner system, TLF laterally free and


5. Top tension system with TLF on rails and no wear

bushing at drill floor 6. Using split tensioner system, TLF on rails

7. Using split tensioner system, TLF on rails and with

additional dolly on surface flow tree

8. Using cased wear joint- can be mixed with first seven

options

9. Using a flexjoint along with a combination of any of the

first seven options

FIGURE 2 – URA - VESSEL INTERFACE (OPTION 1

AND 2)

FIGURE 3 – URA - VESSEL INTERFACE (OPTION 3

AND 4)



FIGURE 4 – URA - VESSEL INTERFACE (OPTION 5,6 AND 7)

FIGURE 5 – URA - VESSEL INTERFACE (OPTION 8 AND 9)

GLOBAL RISER ANALYSIS All the comparisons of bending responses or operability analyses

in this paper are evaluated through global riser analysis. This

typically includes global riser model of intervention riser with

entire set up from conductor through surface equipment and

tension frame. Water depths considered for the strength

comparisons are in range of 5,000 ft-8,000 ft.

MODELLING The intervention riser is modeled in Flexcom (a finite element

program) as an equivalent single string using beam elements.

The model includes the EDP, LRP, wellhead, conductor system

and the surface equipment along with the tension lift frame. For the cased wear joint option, the cased wear joint and riser are

modelled as a pipe-in-pipe structure. Conductor-soil interaction

is modeled using non-linear springs along the conductor string

to represent the P-Y characteristics of the soil. Different upper

riser and vessel interface have different boundary conditions and

are modelled appropriately.

BENDING RESPONSE COMPARISON FOR DIFFERENT URA - VESSEL INTERFACE OPTIONS To understand the effects of parameters in the design on the

performance of an intervention riser system, the following case

study is presented.

For the different vessel interfaces, the bending moment profile

along the upper riser section is presented. The load case includes

a moderate wave and current combined with a vessel offset equal

to 6% of water depth. The system consists of a 6 5/8inch OD

riser pipe with a wall thickness of 0.625 inch and a 2.875 inch

annulus line in 6,300ft water depth.

The bending moment profiles focus on the upper 75m of the

system as there is minimal change to the bending moment profile

in the system below this point as the vessel interface arrangement results in a localized response. The short-dashed lines in the plots

represent the upper and lower elevation of the cased wear joint.

The upper and lower long-dashed lines represent the drill floor

and the tensioner elevation respectively.

Option 1 is a riser system which is only supported vertically at

the point of tension application at the top of the lift frame. In

Option 2, a wear bushing is placed at the drill floor. The presence

of the wear bushing limits horizontal movement of the riser

relative to the drill floor. This lateral restraint prevents the riser

from deflecting and dissipating the load applied to it by the wave

loading and results in an increased bending moment adjacent to the drill floor. The addition of the wear bushing results in the

bending moment at the drill floor increasing from around 50 ft-

kips to almost 370 ft-kips. The benefit of the wear bushing

however, is that the bending moment in the upper section of the

riser adjacent to the lift frame decreases significantly as there is

reduced motion in this section of the riser. This response is

shown in FIGURE 6.



Another option to change the response of the riser system is to

split the tension and apply secondary tension below the drill

floor. The total tension is divided based on an 80/20 split between

the lift frame and the secondary tensioner respectively. The

bending moment profile of the free riser system (Option 1) plotted alongside the bending moment profile of the split

tensioner arrangement (Option 3) is given in FIGURE 7. At the

location of the secondary tensioner the bending moment

increases marginally because of additional lateral restraint being

applied by the tensioner system. The bending moment in the riser

section adjacent to the lift frame is reduced marginally. When a

pipe is under high tensile loads, the structure is stiffer and when

loading is applied to the mid-point, the bending moment is

greatest at the fixity points at either end. In the case of the riser,

the high tension in the system results in high stiffness in the riser

which translates into high bending moments when the wave and

current loading is applied to the system. The decreased tension in the riser section above the secondary tensioner reduces the

stiffness in this section of the riser which results in less bending

moment at this location. The split between the riser tensions can

be controlled to optimize the system design so that the peak

bending moment is at a minimum. As well as improving the

operational limits of the riser, this will also improve the fatigue

performance and the long-term integrity of the system.

Combining the two design changes considered so far, the wear

bushing and the split tensioner systems, results in a bending

moment profile almost identical to that of the wear bushing

alone. The bending moment profiles of Option 1 and Option 4

(wear bushing and split tensioner) are given in FIGURE 8.

Option 5 represents the case where the lift frame to be fixed

laterally to the vessel. This lateral fixity means that the frame is

less compliant to the motions of the riser below the drill floor as

it must match the motions of the vessel. The result is that the

bending moment in the lift frame region increases significantly.

The maximum bending moment occurring in the riser increases by almost 100% and the elevation of the peak bending moment

shifts upwards in the system. Comparison of the bending

moment between Option 1 and Option 5 is shown in FIGURE 9.

The critical section in the system when the lift frame is fixed to

the vessel is directly below the base of the upper frame assembly.

Option 7 consists of the tree to be on skates, thus able to move

freely vertically, but as with the lift frame in Options 5 and 6,

fixed laterally to the vessel. The response is given in FIGURE 9.

The riser response is similar to that demonstrated in the fixity of

the lift frame in that the lateral restraint results in an increased bending moment. As this lateral restraint is lower down in the

system and closer to region of high riser motions, the bending

moment peak is greater. The peak occurs directly at the elevation

of restraint and is around 540 ft-kips which is 60 ft-kips higher

than when the lateral restraint is applied to the lift frame.

Comparison of the bending moment between Option 1 and

Option 6 and between Option 1 and Option 7 is shown in

FIGURE 10 and FIGURE 11, respectively.

FIGURE 6 – OPTION 1 VS OPTION 2










OPERATING ENVELOPE COMPARISON In order to quantify the effect of the load response observed for

different configurations, on operations in field, a comparison is

made by determining the operating limits driven by these loads.

Top Tension System - Varying Rotary Bushing Size Results

In order to compare the effect of the rotary bushing, a range of

bushing inner diameters (IDs) that includes 50 inch, 36 inch, 20

inch and 10 inch are considered. The rotary size of 50 inch

represents the fully open conditions (that is without the rotary)

and the 10 inch rotary indicates a completely closed

configuration. Operating envelopes and wave fatigue are

considered for comparison.

Operating envelopes for the different rotary sizes are given in

FIGURE 12. Operability analysis is performed for multiple

offsets and multiple wave heights up to the 10 year winter storm condition and considers the associated return period current

speeds. For this set of comparisons, a water depth of 7,000 ft and

a typical 6 5/8 inch pipe with 0.625 inch wall is considered. For

all configurations the operability envelopes are driven by the

compensator stroke limit for waves up to 10 ft. Compensator

stroke limit for this condition is ±10 ft. For higher wave heights,

the limits are driven by the stress utilization in the riser. With a

decrease in the bushing size the response shows no operability

for higher wave heights. This is due to an increase in the bending

moment due to the decrease in the rotary bushing ID. ISO

utilization for a range of offsets for different bushing sizes are shown in FIGURE 13. Note that in some cases, clearance

between the riser and the rotary can also be a design criterion for

an open rotary configuration. However, minor clashing of pipe

with drill floor is typically observed and unless high impact is

observed, it is not a concern. Acceptability of clashing depends

on the preference of the contractor and operator.

In summary, the presence of the bushing helps prevent damage

to the pipe due to rattling and contact with the drill floor.

However, it should be noted that operating envelopes will be

reduced if they are limited by riser stress in the URA. Operators

should consider optimizing the ID of the insert bushing if the operating envelopes are narrow whilst using a rotary bushing.

FIGURE 12 – OPERATING ENVELOPE TOP

TENSION SYSTEM (OPTION 2- 50” ROTARY- 10” ROTARY)

FIGURE 13 – ISO UTILIZATION AT ROTARY/INSERT

BUSHING

Split Tension System With and Without Dolly

Operating envelopes for a split tension system, with and without

the dolly, are given in FIGURE 14. For this system, a tension of

50 kips below EDP is maintained by the tensioners at drill floor

which support the riser weight from the tension joint to the EDP.

The weight or the riser above the tension joint, the coiled tubing

equipment and TLF is supported by the top tension applied at the

DSC. Operability analysis is performed for multiple offsets and

multiple wave heights up to the 1 year winter storm condition (16 ft and current of 0.82 knots). For this set of comparisons, a

water depth of 7,000 ft and a typical 7 5/8 inch pipe with 1 inch

wall is considered. For the case without the dolly, operability is

not available in 1 year winter storm conditions. Whereas, for the

case with the dolly, operability envelopes exist for 1 year winter

storm conditions. Operability envelopes are driven by the

bending moment at the transition joint connector (between SFT

and transition joint) for all wave heights.

In general, a split tensioner system provides an additional

support point for the tension in case there is a loss of function in the top drive tensioner. For this scenario having a dolly at the

SFT helps in stabilizing the system by preventing lateral

movement in upper section. With additional constraint at SFT,

the bending moment is transferred to the constraint region and

alleviates bending in other regions, this improves the operating

envelopes just below the surface flow tree that is intersection

transition joint and surface flow tree. However, having an

additional dolly can also be dependent on the vessel selection as

some vessels may not have this facility and

Operators/contractors must ensure sufficient operating limits

exist for the scenario they intend to use.

0.0

5.0

10.0

15.0

20.0

25.0

-10 -8 -6 -4 -2 0 2 4 6 8 10

Sig

nif

ica

nt

Wa

ve

He

igh

t (f

t)

Vessel Offset (% of Water Depth)

Normal Operating - Coil Tubing

11.2 ppg Mixture; 7,000 ft Water Depth; 4,000 psi Surface Pressure

67% Design Limit Criteria; Different Rotary

50" Rotary Bushing

Current Direction

Riser Utilization at Landing Joint

36" Rotary Bushing

20" Rotary Bushing

10" Rotary Bushing

10Yr Winter Storm(0.9 knots surface

current speed)

1Yr Winter Storm(0.8 knots surface

current speed)

90% Non Exceedance

(0.6 knots surface current speed)

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2

-12 -10 -8 -6 -4 -2 0 2 4 6 8 10 12

ISO

Uti

liza

tio

n

Vessel Offset (%)

LANDING JOINT ISO UTILIZATION vs VESSEL OFFSET

Normal Operating - Coil Tubing11.2 Ppg Mixture; 7,000 ft Water Depth; Fd=0.67

15 Deg Wave Heading, No Load Condition

50 inch 36 inch 20 inch 10 inch

ALLOWABLE



FIGURE 14 – OPERATING ENVELOPE SPLIT TENSIONER SYSTEM -WITH DOLLY AND WITHOUT DOLLY

AT SFT (OPTION 7 AND OPTION 3)

With Cased Wear Joint and Upper Stress Joint Assembly and

Without Cased Wear Joint Assembly

Strength analysis is performed considering range of offsets up to

6% (of water depth) vessel offset and 10 year storm conditions

(current of 3.5 knots combined with a Hs of 18 ft). For this

comparison, a water depth of 5,673 ft and a typical 6 5/8 inch

pipe with 0.625 inch wall is considered.

A bending moment plot considering 6% vessel offset, 10 year

winter storm condition (as a percentage of water depth) for the two configurations is shown in FIGURE 15. ISO utilization for

a range of offsets, without wave and current loading at the rotary

bushing location for these two configurations is shown in

FIGURE 16. The riser joint with the cased wear joint has lower

bending moment in the riser at the rotary bushing location

compared to the riser without the cased wear joint. However,

directly above and below the cased wear joint, high bending is

observed in the configuration with the cased wear joint. ISO

utilization in the riser pipe is lower while using the cased wear

joint because the load is taken by the cased wear joint. However,

because of the stiff casing (in CWJ), the connectors above and below the cased wear joint see an increase in bending moment

load. On the contrary, without the cased wear joint, the peak

bending moment occurs the riser pipe at the bushing elevation

and alleviates the connectors above and below that joint.

In general, usage of cased wear joint and upper stress joint can

be an operational decision especially in a high pressure scenario

as this avoids snagging of a high pressure pipe as bending is

taken by external cased wear joint. If snagging of high pressure

pipe in the drill floor region is a concern, having a cased wear

joint is beneficial.

In terms of operability limits, using a cased wear joint is shown

to increases bending around that area and limit riser operability

especially if the connectors above and below the CWJ have

limited structural or functional capacity. However, certain

operational scenarios, safety concerns or risk assessments may

require use of a CWJ. In these cases it is recommended to

optimize the CWJ design for weight, length and stiffness such

that it does not affect rig uptime during operations.

FIGURE 15 – BENDING MOMENT COMPARISON

(WITH AND WITHOUT CASED WEAR JOINT) (OPTION 8 vs OPTION 2)

FIGURE 16 – ISO STRESS UTILIZATION AT

ROTARY (WITH AND WITHOUT CASED WEAR JOINT) ) (OPTION 8 vs OPTION 2)

Effects of a FlexJoint in URA

Upper flexjoints are uncommon for intervention risers. However,

for rigs operating in water depths ranging from shallow to deep

water, upper flexjoints are a viable option. In this study the strength response of the URA with a flexjoint is compared to that

with an upper TSJ. To compare the response, capacity

utilizations of the key components are evaluated.

Utilization tables for the key components considering the URA

flexjoint vs TSJ (upper) are given in TABLE 1 and TABLE 2,

respectively. For this comparison a water depth of 8,000 ft and a

6 5/8 inch pipe with 0.625 inch wall is considered. A wave height

of 14.8 ft Hs and a 1 knot current speed is considered for ± 0 ft

(0.0%), 16 ft (0.2%) and 32 ft (0.4%) vessel offsets. The analysis

0

4

8

12

16

20

-10.0 -8.0 -6.0 -4.0 -2.0 0.0 2.0 4.0 6.0 8.0 10.0

Sig

nif

ica

nt

Wa

ve

He

igh

t (f

t)

Vessel Offset (% Water Depth)

7000FT W & W/O DOLLY - RISER OPERATING ENVELOPEOverpull At EDP Base: 50 Kips, 10.5ppg, 8,000psi Wellhead Pressure

Current Surface Speed 0.82 Knots, 15deg Heading

With Dolly Without Dolly

1year Winter Storm

95% Non-Exceedance

50% Non-Exceedance

Load Direction

5720

5725

5730

5735

5740

5745

5750

5755

5760

5765

0 50 100 150 200 250 300 350 400 450 500

Ele

va

tio

n w

.r.t

. M

ud

lin

e (

ft)

Bending Moment (kips-ft)

BP Thunder Horse 15K OSS IR Analysis

TH SOUTH 15K RISER BENDING COMPARISONSLC #4 - Normal Operating - Coil Tubing

13.8 ppg Mixture; 5,673 ft Water Depth; 9,700 psi MAWHP67% Design Limit Criteria; 10 Year Winter Storm; 6% Vessel Offset

No USJ_37.5 inch Rotary No USJ_11 inch Rotary

With USJ_37.5 inch Rotary 7 1/16 15K Flange BM Capacity

7 1/16 15K Flange Locations

Main

Pip

ePup Jo

int

XO

Master

Swivel/Flow Block

TLF

No USJ Stack-up

Elevator Sub

c

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

-12 -10 -8 -6 -4 -2 0 2 4 6 8 10 12

Ris

er

Uti

liza

tio

n (

-)

Offset (% of Water Depth)

BP Thunder Horse 15K OSS IR Analysis

TH SOUTH 15K RISER ISO UTILIZATION COMPARISONSLC #4 - Normal Operating - Coil Tubing

13.8 ppg Mixture; 5,673 ft Water Depth; 9,700 psi MAWHP67% Design Limit Criteria; 15 deg Wave Heading

No USJ_37.5 inch Rotary No USJ_11 inch Rotary With USJ_37.5 inch Rotary Limit

cc

c ccc



considers a flexjoint with a rotational stiffness of 11 kips-ft/deg.

This comparison considers 6,000 psi surface pressure. The riser

ISO utilizations between the two configurations indicate that the

configuration with TSJ has better utilization ratios compared to

configuration with flexjoint. This is primarily driven by the peak bending in the drill pipe below the drill floor. The decreased

stiffness of the URA when using the flexjoint results in more

bending in the drill pipe below the drill floor.

In terms of operating envelopes, the riser system with upper TSJ

shows a better response. In addition, upper stress joint is low

maintenance compared to flexjoints.

TABLE 1 – COMPONENT UTILIZATIONS WITH

FLEXJOINT (OPTION 9)

TABLE 2 – COMPONENT UTILIZATIONS WITHOUT

FLEXJOINT (OPTION 1)

CONCLUSIONS As demonstrated in the case studies, the structural performance

of the upper riser is sensitive to the interface between the vessel

and the riser system.

Comparison of different bushing sizes shows that the riser

stresses at the bushing location increase as the size of the rotary

table opening reduces. However, in the riser section above the

rotary bushing, the bending moment decreases as the rotary

bushing ID is reduced. The selection of the size of rotary bushing

to use must be based on the specific riser system and a rotary

bushing size which balances the performance of components

above the rotary table with that below. This typically is a function

of stress response in the system. In addition to controlling the

bending response of the system, the presence of the bushing

helps prevent damage to the pipe due to rattling and contact with the drill floor. Operators should consider optimizing the ID of

the insert bushing if the operating envelopes are narrow whilst

using a rotary bushing.

From comparison of split tensioner system with and without

dolly it is evident that in terms of strength response wider

operability envelopes are available if dolly is used at the SFT to

stabilize the design. Hence, if split tensioner system is used, it is

recommended to include dolly on the surface flow tree if the

vessel has feasibility. Note that the response is only based on one

rig response and one riser system. The response can be different

for different vessel and different riser system. Moreover, a split

tensioner system provides an additional support point for the

tension in case there is a loss of function in the top drive tensioner. For this scenario having a dolly at the SFT helps in

stabilizing the system from lateral movement in upper section.

From comparison of the with and without cased wear joint

configurations, the riser joint with the cased wear joint shows

lower bending moment in the riser at the rotary bushing location

compared to the riser without the cased wear joint. However,

high bending is observed directly above and below the cased

wear joint in the configuration with the cased wear joint. Using

a cased wear joint is shown to increases bending around that area

and limit riser operability especially if the connectors above and

below the CWJ have limited structural or functional capacity. However, certain operational scenarios, safety concerns or risk

assessments may require use of a CWJ. In these cases it is

recommended to optimize the CWJ design for weight, length and

stiffness such that it does not affect rig uptime during operations

From comparison of the configurations flexjoint and TSJ, the

riser system with the TSJ shows a better response. In addition to

structural response, using an TSJ is recommended as it is more

robust and low maintenance compared to flexjoints.

Each of the URA options and vessel interfaces discussed have their own advantages and disadvantages. By considering the

options available to each riser system, modifications can be

made to the vessel interface to improve the operability

envelopes. Flexibility in the riser design and capability to switch

between different options can enable operations in a wide range

of water depths and operating environments. Operators/

contractors should be aware of the various available URA and

vessel interface options available to them, the effect of each

configuration on the response of the system and the operability

they can expect. Moreover, each of these configurations can be

optimized such that they do not hamper operability and

maximize rig uptime for operations.

ACKNOWLEDGMENTS The authors thank the management of Helix and 2H Offshore for

their approval and support in the publication and presentation of

this paper. The authors also acknowledge the support and

collaboration of engineers across 2H’s worldwide offices in

presenting this study.

REFERENCES [1] API – “Recommended Practice for

Completion/Workover Risers”; API-RP-17G, 2nd Edition (ISO 13628-7:2005); July 2006 (Reaffirmed April 2011).

[2] DNVGL – “Fatigue Design of Offshore Steel

Structures”, DNVGL-RP-0005, Revision 6, 2014


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