Drilling Riser, Wellhead and Conductor Structural Integrity Management in New and

Remote Offshore Regions

Tim Farrant – BP Exploration Operating Co. Ltd UK

Hugh Howells – 2H Offshore Engineering Ltd, UK

Neil Robertson – Boreas Consultants Ltd, UK

The assurance of drilling riser, wellhead and conductor structural integrity at new sites and

remote locations requires a careful approach to risk management. Uncertainty in

environmental conditions, practical constraints such as equipment and accessibility, and

optimisation of life cycle costs for potential future developments leads to a range of risk

management strategies that are tailored to the local conditions and project requirements. This

paper discusses the risk management process and factors such as the ocean current climate,

soil conditions, conductor strength, the well life cycle and the possible mitigation measures

such as hardware upgrade, operating procedures, riser monitoring and VIV suppression

devices. Future trends will be discussed, focussing on advances in hardware design and

modifications to existing equipment. The paper is based on BP’s experience of drilling

conventional wells in regions such as Sakhalin V and West of Shetland, and HPHT wells in

the Caspian Sea and Egypt West Nile Delta.

Introduction

Drilling costs often represent the largest proportion of CAPEX for greenfield developments.

A single appraisal well in a deepwater or remote region may represent an investment of the

order of $50-100M. There is also a growing trend for drilling rigs to stay connected to the

wellhead for longer durations due to financial drivers such as; the need to access deeper

HPHT gas fields, sidetrack during appraisal drilling, conversion of appraisal wells for

production (so called ‘keepers’) and use of drill-through workover practices. HPHT wells are

now being drilled to depths of TVD 4500m over durations ranging from a few months to two

years. In this context, there is a strong business case for risk management of the structural

integrity of the riser, wellhead and conductor system to ensure that the drilling campaign does

not stray outside of regulatory and corporate standards for safety, the environment, reputation

and business risk. In new and remote regions drilling operations are characterised by

comparatively short rig contracts, fast mobilisation but long rig transits, long lead times for

procurement and supply of equipment, limited environmental data and uncertainty on the

eventual use of the wells.

The Risk Management Process

A general process for the risk management of wellhead structural integrity is shown in Figure

1. The process follows a cycle of risk assessment, analysis, implementation and lessons learnt

feedback that is intended to promote continual improvement. Each stage in the process is

discussed in this paper.

Figure 1 – A typical risk management process

A key feature of the process is the separation of the drilling activities from the structural

assessment. These activities usually have to happen in parallel to meet schedule requirements.

This feature gives rise to the need for a flexible and adaptive approach to management of

wellhead structural integrity that takes account of practical constraints, such as the supply

chain capability, when selecting mitigation measures.

Preliminary Planning and Standardisation

Reliability of drilling and wellhead equipment can be greatly improved by adopting the

principles of standardisation during the preliminary planning phase of a drilling campaign.

These principles are implemented by developing standardised contracts and specifications

which define key requirements and expectations for drilling risers and wellhead structural

integrity. This can help to minimise repetition of past mistakes and is a key component of

knowledge management. These documents include:

- Analysis and inspection requirements in global group-wide model rig contracts

- A universal subsea wellhead specification

- A standardised subsea conductor design

A key factor in the effectiveness of these documents is the communication to the contractor or

vendor of any special requirements, followed up by effective quality control processes that

ensure that equipment is delivered according to the specified requirements.

Global Model Contract

The global model rig contract provides a means for lessons learnt from major incidents and

mitigations to be agreed during the contract negotiations. Areas addressed included:

- Hardness survey requirements for high strength bolted riser connections to avoid

brittle fracture.

- Choke and kill line maintenance practices for example seal replacement, gap

tolerances and clamp tightness

- Corrosion protection measures for the riser

- Riser tension management strategy. Inadequate tension may potentially damage the

riser and wellhead due to accelerated fatigue damage

- Riser disconnect procedures for harsh weather and dynamic positioning malfunction

- Riser joint inspection requirements for wall thickness and fatigue cracks

- Swivel maintenance for tension rings on dynamically positioned rigs. Weathervaning

of DP rigs has been known to unscrew or back out threaded connections on conductor

and surface casing strings.

Universal Subsea Wellhead Specification

This defines functional and structural requirements for purchase of subsea wellhead systems

and ensures that the wellhead has the ability to be used for long-term production with both

moored and dynamically positioned rigs. The document features requirements for:

- Wellhead housing and casing hanger lockdown mechanisms

- Pack-offs, gaskets and sealing surfaces

- Extension joint welded fabrication

- Torque capacity

- Analysis requirements

- Wear bushings

- Debris caps

An important feature of modern subsea wellheads is that as much of the bending load from

the riser as possible is transferred to the conductor pipe. This allows most of the cyclic

stresses to be resisted by the principal structural member, thus protecting the high pressure

housing and inner casing strings from excessive fatigue damage. This optimum load transfer

is usually achieved by the use of a rigid lock down wellhead system which pre-loads the high

pressure housing into the low pressure housing and has two load shoulders to facilitate

bending moment transfer.

Figure 2 - An example of a rigid lock down wellhead (courtesy of Dril-Quip)

Standardised Subsea Conductor Design

Engineering studies or experience in other regions may be used to define a standardised

design for the conductor. This improves the likelihood that the conductor joints, which are

often on a long lead time, will be fit for purpose when the detailed engineering phase of any

field development is undertaken, often years later. This standardised conductor design might

consider issues such as:

- pipe diameter and wall thickness

- rig handling capabilities and joint handling details

- connector design e.g. thread type and anti rotation keys

- weld fabrication requirements

- typical riser loading from extreme rig offset

- wellhead displacement and rotation and how this might affect drilling riser flex-joint

angles and production spool stresses

- worst case soil strength and fatigue loading based on historical data – if available and

relevant

In weak soils, an important decision in the specification of the conductor is the choice of

connection approximately 10m below the mudline. Where there is significant risk of fatigue

loading or high bending loads, it is sometimes necessary to specify higher capacity fatigue

resistant connectors such as the Dril-Quip HC100 or Vetco RL-4RB.

Risk Review

Once the well location is known, it is desirable to have a risk review of the structural integrity

of the riser and wellhead system, based on the available information such as:

- The casing programme and drilling schedule

- Previous experience in the area

- Metocean data and geotechnical data

- Geo-hazard assessment

- Rig and riser data

- Standardised wellhead and conductor specifications

The objective of the review is to identify potential risks, defined detailed analysis work scope

for the fitness for purpose assessment and anticipate the need for procurement of any special

equipment, such as premium conductor connectors. The review is initiated by the senior

drilling engineer and usually requires a discussion with specialists in the structural, risers,

metocean and geotechnical disciplines. The review is based on previous experience and the

information available at the time. The objective is to anticipate critical issues in advance of

detailed analysis and survey results becoming available. If relevant structural analysis has

already been performed, there is previous operational experience in the area and no new risks

are identified, it may be acceptable to forego further evaluation of structural integrity. For

new and remote regions, however, by definition, this is unlikely to be the case.

Fitness for Purpose and Detailed Riser Analysis

A full description of the activities required to assure integrity of drilling riser systems and

casing installation can be found in Ref. 1. Operators tend to place particular emphasis on

managing the through-life integrity of the wellhead and conductor system. While integrity of

the whole drilling operation is important, integrity of the equipment supplied by the drilling

contractor is usually managed through the terms of the rig contract. Therefore detailed

analysis carried out by the operator often has a focus on the following potential threats:

- Damage to the wellhead from extreme loading induced by riser and rig motions

- Fatigue loading from riser dynamic motions due to ocean current and wave

A typical riser and wellhead configuration, and the environmental loading induced upon it, is

shown Figure 3. Lateral loads on the riser string are transmitted down the riser and into the

wellhead system, which often becomes the most critical part of the system for structural

integrity. A key outcome from the fitness for purpose assessment is to determine the need for

further mitigation such as modifications to hardware or operating procedures.

Extreme Loading Due to Vessel Offset

The function of the conductor is to provide support casing weight, particularly while

cementing of the surface string takes place, and provide resistance to lateral loading (e.g. from

risers, production spools loads, trawl board interaction). During connected-riser operations,

vessel offset and current loading on the riser cause lateral loading on the conductor pipe and

the connectors between the BOP, wellhead and conductor joints.

Figure 4 shows a small scale test of a conductor subjected to large lateral offset that has

resulted in plastic deformation of the pipe. A wellhead subjected to such loading will,

effectively, be unusable due to the deformed angle of the wellhead. There is also a risk of loss

of well control if the wellhead to BOP connector is overloaded. Figure 5 gives and example of

the bending moment in a conductor system in weak soils, compared with the capacities of the

conductor pipe and wellhead system components. Peak loading in the conductor often occurs

at a depth of 8 to 10m below the mudline, which is often a critical location in the system

design. The survival limit is the point at which permanent damage is likely to be done to the

conductor and wellhead. For moored rigs, it is desirable that the survival limit is greater than

the maximum offset obtained from the damaged mooring line analysis for the rig. The overall

combined failure probability, and hence the risk, depends on the joint probability of:

- the combinations of wind, wave and associated ocean current

- the probability of the riser not being disconnected

- probability of a mooring line failure

This combined failure probability also has to be weighted by the planned duration of the

drilling operation (the ‘exposure’ time) and account taken for seasonal variation of conditions.

Figure 3 – Loading on the riser and subsea wellhead system

Figure 4 – Scale model test of conductor in weak soil at extreme offset, showing

permanent deformation (Ref. 2)

Figure 5 – Bending moment in the wellhead system under extreme lateral loading for

lower bound (weak) and upper bound (strong) soils.

As water depth increases it may become necessary to resort to stronger conductor designs as

the mooring system becomes allows higher rig offsets and the drag and weight of the riser

string increases. If preliminary comparisons of the mooring and the conductor analysis for

extreme storms (e.g. 10-year storm) indicate that risk of overstress may be comparatively

high, the following options might be typically considered:

1. Carry out an operability simulation to determine a more accurate estimate of the

probability of failure for the conductor

2. Increase the strength of the conductor

3. Set more conservative limits for disconnection

Upgrading the conductor strength is often the most straight forward option, provided there is

sufficient lead time, and has the added merit of materially increasing the reliability of the

system.

Similarly, for dynamically positioned rigs the probability of plastically deforming the

conductor will depend on:

- the combinations of wind, wave and associated ocean current

- the probability of the riser not being disconnected in time

- probability of a drift-off or drive-off event

Typically drift off simulations are carried out assuming worst case combination of wind, wave

and current. These simulations are then used to define well specific operating criteria, for use

by the operations team when deciding to initiate emergency disconnection procedures. Recent

developments in DP operations have lead to use of real-time onboard simulators that seek to

re-assess the operating criteria based on the prevailing weather conditions (Ref. 3).

Riser Induced Fatigue of the Wellhead System

With the riser attached, fatigue is induced in the wellhead by vessel motions, wave loading on

the riser string and vortex-induced-vibration (VIV, see Ref. 4 for an introduction) as

illustrated in Figure 3 . This loading results in cyclic bending stress which can cause fatigue

crack growth in the structural components of the wellhead and conductor system. Figure 6

shows a crack that has been growing through a girth weld.

Figure 6 – A typical fatigue crack in a pipe girth weld (courtesy of TWI)

If crack growth is allowed to continue to the point where the entire conductor string separates,

the consequences may be progressive fatigue failure of the casing strings inside or permanent

Cracking

Pipe weld

cyclic stress

damage to the well. Typically, casing strings are design to take static pressure and axial loads

only and have lower bending capacity and fatigue resistance than the conductor. An example

of a fatigue failure that occurred due to a combination of VIV and the use of a wellhead

without two load shoulders is given in Ref. 5. The failure occurred at the base of the high

pressure housing in the transition to the first casing joint.

Figure 7 – Fatigue failure of a high pressure wellhead housing

The first step in the fatigue assessment is to collate the available wave and current statistical

data, soils data and define a likely life cycle for the well. Examples of the well life cycles are

given in Table 1. Where the life cycle involves separate phases, this can sometimes be

exploited by adopting a ‘monitor and see’ approach as a mitigation to fatigue damage

accumulated over the whole life cycle because there will be opportunities to intervene, if

necessary.

Well Type Water depth Max Duration (per well)

A Exploration 100m 80 days

10 days/well Plug & Abandon

Total = 3 months

B Production 100m-500m 50 days initial drilling &completion

15 days workover

50 days sidetrack or re-completion

10 days/well Plug & Abandon

Total = 4.2 months

C HPHT appraisal

followed by

production

480-600m 7 mths appraisal

2 mths prod. conversion thru tree

2 mths future prod. side track

Total = 11 months

Table 1 – Typical well programme durations

Wave and VIV fatigue analysis needs to account for all phases of the well life cycle.

Important parameters in this analysis are the subsea stack-up configuration, soil stiffness data,

water depth, wave environment and through-depth ocean current statistics. Figure 3 shows the

elevations of fatigue details that can be critical in determining the fatigue life of the overall

wellhead and conductor system. A crucial dimension for the configuration is the height of the

flex-joint above the mud-line. The bending stress induced in the conductor is directly

proportional to this distance and, as a rule of thumb, the fatigue damage rate is proportional to

the third or forth power of this. Where through-tree operations are anticipated during the

production phase of the well, the fatigue endurance required of the conductor is greatly

increased (see Figure 8).

Soil stiffness governs the depth to which the conductor needs to be resistant to fatigue

loading. In weak soils significant loading can be occur in the region of 10m below the

mudline. In soils such as stiff clays and dense sands the majority of the conductor may be

protected from fatigue loading. Soil stiffness can vary widely depending on the specific

location of the well site, which means it is often necessary to assume weak soils could be

present. This is often the case in new and remote regions where accurate geotechnical

information is either unavailable or inacurate.

Figure 8 – Fatigue life distribution with depth below the mud-line in weak soil

Wave, current and water depth combine to define the fatigue loading that will be seen by the

wellhead system. Drilling operations typically have durations that are short compared to the

metocean cycles that drive the environmental loading (e.g. seasons, tidal cycles and storm

surges). Therefore, carefully consideration needs to be given to the selection of metocean data

relevant to the likely period of operations. Wave height versus period statistical data (usually

as scatter diagrams) are used to characterise the severity of the wave environment. Wave

fatigue is particularly significant in shallower water depths (<1000m) where the motions

induced at the top of the riser are not attenuated significantly from the surface by the length of

the riser. The stronger and more slab-like the currents at the well location, the higher the risk

of vortex-induced vibration. The current environment is highly dependent on location, as

shown by Figure 9. This illustrates the importance of having access to through-depth current

metocean statistics close to the well site. In deepwater, fatigue damage predicted at the

wellhead due to VIV may actually be less than the shallow water case due to the reduced

currents speeds in the lower part of the water column. Further discussion of riser fatigue

assessment techniques can be found in Ref. 4 and 6.

Figure 9 – Comparison of current profiles in different regions and water depth

Fatigue Life Safety Factors and Risk

Reliability methods such as FORM and Monte Carlo simulations can be used to relate fatigue

life predictions and safety factors to a probability of failure. This is discussed in Ref. 6 and 7

and example is given in Figure 10 that shows the relationship between safety factor and

failure probability for a given uncertainty in the prediction technique. This uncertainty, as a

rough estimate, could be determined by calibration with traditional fatigue design practices

(e.g. wave fatigue safety factor of 10 corresponds to pf ≈ 10-5) however care needs to be taken

in critical applications to ensure that this approach is valid, carrying out more detailed

calculations following the methods described in Ref. 6 if necessary. Typically wellhead

equipment will be designed to a ‘High’ safety class requiring a target annual probability of

failure of 10-5. However, if this reliability level is not achievable by design the use of

corporate risk criteria, expressed as a frequency versus consequence matrix (see Figure 11)

for major accident risk, can give the flexibility to determine effective mitigations and reduce

the risk to As Low as Reasonably Practical (ALARP). Potential mitigation methods are

discussed later in this paper. In new and remote regions this approach often becomes essential

because the lack of previous experience and uncertainty in computer models (which often

over predict fatigue) can result in very onerous ‘worst case’ fatigue predictions that may need

to be put into context with further analysis cases, based on less conservative modelling

assumptions, or mitigated. Figure 12 illustrates the dramatic difference between idealised

‘worst case’ riser modelling predictions and the actual riser behaviour determined from field

measurements for a case where bare joints have been wrapped with a rope as a mitigation

measure. The use of such a risk assessment format is still very novel and there are many

uncertainties, particularly because there are no meaningful failure statistics available for such

systems that might be used for validation. However, the approach has value in that it provides

a framework for relative comparison of risks between different drilling campaigns and across

different regions. BP has, for many years, been analysing drilling riser monitoring data to

quantify the uncertainty in the VIV computer models, which is a major source of uncertainty

in the fatigue analysis (see Refs. 8, 9 and 10, for example).

Uncetainty in model prediction

0

5

10

15

20

25

1.E-05 1.E-04 1.E-03

annual probability of failure per riser

Fatig

ue L

ife S

afet

y Fa

ctor

std deviation =0.17

std deviation =0.27

Figure 10 – Typical relationship between annual failure probability and fatigue life

safety factors (using Ref. 6)

Figure 11 - Major Accident Risk Matrix Hardware and Operational Mitigations

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 0.5 1 1.5 2Current Velocity (m)

Ris

er C

ross

Flo

w A

ccel

erat

ion

(m/s

2 )

Actual response measured in the field for bare joint with rope wrap

Idealised response predicted by computer model with cylindrical cross section

Figure 12 - Comparison of predicted VIV response versus field measurements

Mitigation of Vortex Induced Vibration

Vortex induced vibration can occur when the vortices that form behind a bluff drilling riser

joint shed with a frequency that coincides with the natural resonant frequencies of the riser

string. When this happens, vigorous vibration of the riser can result at frequencies on the

region of 2.5Hz. In high current regions, this can lead to rapid accumulation of fatigue

damage in the wellhead system, if some mitigation in not implemented. Two types of

modifications can be applied to the riser string to mitigate VIV:

- Helical strakes and fins – these work by disrupting the synchronisation (aka.

correlation) of the vortices along the length of the riser.

- Fairings – these attempt to reduce the strength of the vortices by streamlining the

bluff riser cross section.

For shallow water or bare joint applications, where there are a limited number of riser joints

and no buoyancy is used, rope wrapping or fitting 3 start strakes to the 21 inch pipe of bare

riser joints may be an effective means of suppressing vortex induced vibration (see Figure

13). Experience within the industry of running casing strings, and experimental studies such

as Ref. 11, have shown these methods to be effective. However, the effect of the peripheral

lines, such as the choke and kill lines, on hydrodynamic behaviour is not fully understood. BP

is conducting further research, supported by field measurements, to better understand the

effectiveness of such methods. These techniques have the advantages of low cost, ease of

application at short notice and robustness during handling operations. In remote regions,

where the drill rig may be in transit to the well site months before the drilling operations start,

these techniques provide a realistic practical mitigation option for VIV concerns. Riser fins

may also provide a similar effect and have the added benefit of protecting the riser from

damage during handling. However, procurement manufacturing lead time may be a limitation

for this solution and work is still ongoing to determine their effectiveness for VIV

suppression.

For risers with buoyancy the options are more limited. Applying strakes to the buoyancy has

lead to practical difficulties during handling, leading to damage to the strakes, especially as

they are run through constrictions such as the diverter housing (see Figure 13). For deepwater

riser systems there is renewed interest in fairing systems (see Figure 14) because of the

combined advantages of VIV mitigation and drag reduction, which increases the operability

of the riser system in deepwater high current environments such as the Gulf of Mexico. These

systems may have potential disadvantages for drilling operations in new and remote areas

because of the time needed to procure and ship the equipment. The fairings are also

comparatively complicated to install, a process which cannot be done until the riser is run,

which may introduce costly delays to riser operations if the rig has no previous experience of

such equipment.

Figure 13 – 4” rope wrap (lhs), rubber 3 -start strakes mechanically attached to bare

joints (rhs top) and disbonded strakes glued on buoyant riser joints (rhs bottom)

Figure 14 - Riser fins (lhs) and fairings (rhs)

Structural Monitoring

In spite of best efforts to analyse the loading seen by the wellhead system using computer

models, inevitably there remains considerable uncertainty as to whether the predicted

behaviour will actually manifest itself during the real operation. Analysis predictions are

generally seen as a worst case scenario. One approach to mitigation of fatigue failure is to

adopt a ‘monitor and see’ approach by using structural monitoring instrumentation. In this

way it is possible to keep a record of the accumulation of fatigue damage, intervening if there

if the potential risk manifests itself. This approach is particularly effective if the drilling

programme involves several phases, possibly years apart e.g. appraisal drilling, production

side track, completion and workover, allowing timely evaluation of monitoring data.

A range of different of different monitoring schemes are possible, however, stand alone

(battery powered and wireless) systems lend themselves most readily to temporary

deployment at short notice. These can be deployed and retrieved with the riser or recovered

by ROV (see Figure 15) and will typically measure motions rather than direct measurement of

stress, strain or fatigue damage in the structure. This leads to the main disadvantage of these

systems in that the interpretation of the gathered data can be difficult, requiring considerable

effort from specialist engineering contractors. However, in its simplest form the monitoring

allows accelerations at the wellhead to be related to the wellhead fatigue damage through a

look-up type chart (see Figure 16). Through-depth current data is also valuable in assessing

the likelihood of VIV and is usually gathered through the use of acoustic Doppler current

profiler.

Figure 15 – Stand alone motion logger

If there is concern about potentially very rapid damage of the wellhead, it is possible to set-up

a real time monitoring system so that motions can be monitored on a day-to-day basis on

board the drilling rig. For this approach to be successful significant effort needs to be put into

development of operating procedures and the setting of well specific operating criteria. The

subsea cabling or umbilical needed to implement this type of system also makes it less

reliable and more prone to damage, especially during harsh weather. Other factors affecting

the success of the monitoring campaign include accurate record keeping in the Daily Drilling

Report of seastate, mud weight and riser tension.

Contingency Plans

Drilling in new and remote regions can lead to situations which result in a wellhead

configuration that is outside the assumed parameters in the base case structural integrity

assessment. For this reason it is advisable to consider sensitivity cases in advance so that

information is available to the drilling team in the event that difficulties arise.

0.000001

0.00001

0.0001

0.001

0.01

0.1

1

10

100

1000

1.E-11 1.E-10 1.E-09 1.E-08 1.E-07 1.E-06 1.E-05 1.E-04 1.E-03 1.E-02 1.E-01

Frequency x Acceleration3 (m³/s7)

Fati

gue

Dam

age

(1/Y

ears

)

0

5

10

15

20

25

Logg

er R

MS

Mea

sure

men

t Er

ror

(%)

Wave fatigue

VIV fatigue

Measurement error

Figure 16 - Relationship between acceleration and wellhead fatigue

Figure 17 - Real time monitoring system

The list of sensitivity cases should be derived from the risk assessment processes which will

have already been undertaken for the well, however, typical ones include:

- Acceptable stick-up height range – uncertainty in the shallow formations can lead

to jetting refusal and the conductor being set high (more stick-up).

- Cement shortfall in the event of cement losses or top-up system malfunction.

- More severe metocean conditions than predicted

- Washout due to seabed currents

- Analysis of the operating envelope for the wellhead if the high pressure housing

cannot be locked into the low pressure housing – this involves consideration of the

surface casing strength and fatigue life.

- Review of the effect of cement short fall between the first casing string and the

conductor – worth questioning whether cementing to surface is required at all.

- Loading from unusual events such as landslides or turbidity flows.

In analysing the above cases, the objective is to define allowable ranges for measurable

parameters, such as conductor stick-up, cement height, flex-joint angle, bull’s-eye indicators

etc. Analysis needs to consider riser and wellhead system behaviour while connected,

transiently during disconnection and once emergency disconnection has taken place. Ref. 12

provides some criteria for disconnected conductor stability.

Management of Change (MoC)

As the drilling programme progresses, it should be recognised that there will be pressure to

modify the structural design of the wellhead to accommodate:

- Changes of equipment vendors

- Make use of spares / delays in availability of new equipment

- New requirements such as production equipment, protection structures etc.

- Change in rig type e.g. from moored to DP.

- New drilling rig joint length preferences etc.

Such changes need to be controlled using a management of change procedure where a

Technical Authority is identified for structural integrity. Examples of areas where MOC needs

to be applied include:

- Pipe wall thickness weld details (fit up, single sided, double sided and ground flush)

- Conductor connector type

- Changes to the high pressure housing and its interface with the low pressure housing

- Swage transitions between different pipe sizes

- Specification of cement top-up systems requiring welded attachment

- Last minute changes such as handling pad-eyes welded onto doubler plates or screwed

into threaded sockets.

Conclusions

An overview is given of a risk management process for structural integrity of drilling risers

and subsea wellhead systems. The process is based on BP’s experience drilling wells in new

and remote regions and places emphasis on practical mitigations combined with quantitative

risk assessment methods. The techniques and methodologies discussed are the subject of

further research within the industry. In particular, the following areas are the subject of

ongoing research programmes:

- Validation of fatigue safety factors and reliability based on full scale monitoring data

- Qualification of conductor connectors for high fatigue application

- Testing of VIV suppression techniques for bare and buoyant drilling riser joints

The objective of this work is to develop a practical approach to risk management that is

aligned with previous experience, the limitations of predictive models, schedule requirements,

cost constraints and supply chain capability.

References

1. 2H Offshore Engineering Ltd, ‘Atlantic Margin Joint Industry Group’, Deep Water

Drilling Riser Integrity Management Guidelines, October 1998.

2. Drilling Engineering Association (Europe), Project DEA (E) 101,’Improved Methods

for Conductor Design and Assessment of Trawl Gear Snagging’, Final project report,

volume 1, results of analysis and field testing, September 2004.

3. James Brekke, Donogh Lang, Enda O’Sullivan ‘On-Board Generation of Alert Offsets

for Dynamically-Positioned Vessels’, DOT XVI, New Orleans, LA.

4. J.L.Thorogood, A.S. Train and A.J. Adams, ‘Deep Water Riser System Design and

Management’, IADC/SPE Drilling Conference 39295, March 1998.

5. Hopper, C.T., “Vortex Induced Oscillations of Long Marine Drilling Risers”, Proc.

Deep Offshore Technology Conf., Malta, 1983.

6. DNV, ‘Riser Fatigue ‘, RP F204.

7. Stahl, B. and Banon, H. ‘Fatigue Safety Factor for Deepwater Risers’, Proc. OMAE,

Paper no. 28405, Oslo, June 2002.

8. A Sworn and H Howells, ‘Fatigue Life Evaluation Through the Calibration of a VIV

Prediction Tool with Full Scale Field Measurements at the Schiehallion Field’, DOT

Sep 2003.

9. R Shilling, M Campbell and Howells, ‘Drilling Riser Vortex Induced Vibration

Analysis Calibration Using Full Scale Field Data’, DOT Nov 2005.

10. R James, ‘VIV of a deepwater drilling riser in complex currents’, Flow Induced

Vibration conference, July 2004.

11. M Falco, F Fossati & F. Resta, ‘On Vortex Induced Vibration of Marine Cables:

Design Optimisation of Wrapped Cables for Controlling Vibrations’

12. B Stahl and M. P. Baur, Amoco (U.K.) Exploration Co., ‘Design Methodology for

Offshore Platform Conductors’, OTC 3902, 1980.