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
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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
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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
wear bushing at drill floor
4. Using split tensioner system, TLF laterally free and
wear bushing at drill floor
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)
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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.
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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
FIGURE 7 – OPTION 1 VS OPTION 3
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FIGURE 8 – OPTION 1 VS OPTION 4
FIGURE 9 – OPTION 1 VS OPTION 5
FIGURE 10 – OPTION 1 VS OPTION 6
FIGURE 11 – OPTION 1 VS OPTION 7
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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
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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
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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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