subsea dropped object and layout study

Britannia

BRITANNIA PROJECT

SUBSEA DIVISION

DOCUMENT

TITLE: SUBSEA DROPPED OBJECT AND LAYOUT STUDY

NUMBER: BRT2-XSO-NR-S0-55-00011

PAGES: 1 OF 63

D2

D1

B1

REVISED FOR DESIGN

ISSUED FOR DETAIL DESIGN

ISSUED FOR COMMENT

SPD

SPD

7/4/95

13/9/94

PAH

AP

7/4/95

13/9/94

SPD

SPD

AP 9/4/95

REV ISSUE OR REVISION DESCRIPTION ORIGIN BY

DATE CH'KDBY

DATE PEEng. Mgr/ Div

Mgr*

DATE

APPROVAL

As Appropriate

Subsea Dropped Objectand Layout Study

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Subsea Dropped Object and Layout Study

TABLE OF CONTENTS

1.0 Introduction

1.1 Purpose1.2 Scope1.3 Abbreviations

2.0 Recommendations

2.1 Recommendations for Batch Setting and Pre-Drilling Operations2.2 Recommendations for Completion and Future Workover and Intervention Operations2.3 Recommendations for Future Drilling Operations2.4 General Recommendations for all Drilling and Intervention Activities2.5 Recommendations for Further Work

3.0 Dropped Objects and Impacts

3.1 Overview of Methodology3.1.1 Load Case Criteria3.1.2 As Built Dropped Object and Impact Protection

3.2 Detailed Hazard Review3.2.1 Review of Subsea Hazard Identification and Screening Study3.2.2 Dropped Object and Impact Hazards Listing

3.3 Dropped Object and Impact Analysis3.3.1 Dropped BOP3.3.2 Dropped Tree3.3.3 Dropped Tubulars3.3.4 Dropped Containers3.3.5 Dropped Tools, Equipment and Other Objects3.3.6 Dropped Equipment for Wireline and Coiled Tubing Operations3.3.7 Dropped Anchors and Related Impacts3.3.8 Dropped Objects and Impacts during Intervention Operations3.3.9 Impact from Other Major Accidents3.3.10 Impacts from Fishing Activity

3.4 Hazard Classifications3.5 Protection Criteria

4.0 Subsea Layout

4.1 Rig Considerations4.1.1 Proposed Mooring Pattern4.1.2 Catenary Touch Down Points4.1.3 Preferred Rig Heading4.1.4 Overall Dimensions of Main Deck4.1.5 Rig Side for Loading of Trees4.1.6 Rig Side for Loading of Tubulars

4.2 Typical Rig Geometries4.3 Seabed Layout Design Objectives4.4 Layout of Subsea Facilities

5.0 References

Appendix 1 Tables and Figures

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1.0 INTRODUCTION

The seabed layout of the subsea facilities and the protective measures applied in design have a significant effect on the potential for damage, hydrocarbon releases and remedial work. These factors have a major influence on the inherent risks associated with the facilities and as such should be optimised to ensure safety in design.

This study presents an assessment of the dropped object and impact hazards associated with the Britannia subsea facilities. This assessment is used to generate design criteria for protective requirements and develop the seabed layout of the subsea facilities.

Following design implementation, this document has been revised to reflect the residual risks associated with dropped objects taking into consideration the dropped object protection incorporated into the design of the subsea facilities.

This study is identified in the Project Safety Plan (Ref. 1) as a requirement for the preliminary engineering phase of the project.

1.1 Purpose

The main purpose of this document is to provide a logical basis for the seabed layout of the subsea facilities that meets the following objectives.

· To identify all potential dropped object and impact hazards that can affect the subsea facilities and to assess their potential to cause damage, hydrocarbon releases, impact on the environment and subsequent remedial activities.

· To develop a seabed layout for the subsea facilities that minimises the likelihood of these hazards occurring.

· To determine protective measures for the subsea facilities necessary to avoid damage, releases and remedial activities where it is not possible to eliminate hazards by optimisation of the seabed layout.

· To identify procedural measures that can be adopted to minimise hazards where physical protection is impractical or not cost effective based on the dropped object protection incorporated into the design of the subsea facilities.

· To provide an auditable trail of design decisions to help demonstrate that risk have been reduced to a level that is as low as reasonably practical.

This work also satisfies two general recommendations made in the Subsea Hazard Identification and Screening Report (Ref. 2), issued as Safety Action Records, as follows.

SS-010-013 Assess requirement for protection of subsea wells during design.SS-010-030 Implement protection of subsea facilities by procedural methods if physical protection

is impractical.

1.2 Scope

This study provides a thorough assessment of all dropped object and impact hazards on the subsea facilities that could affect the seabed layout or procedural requirements.

The study considers dropped object and impact hazards for the following phases over the field life.

· Initial batch setting and pre-drilling phase from semi submersible drilling rig (no subsea facilities installed at this stage) during which 8 guide bases will be set with 36", 30" and 20" casing. These wells will then be drilled and casing and liner set but not completed. These wells will be plugged and left in a safe condition and the drilling rig demobilised.

· Installation of flowlines and manifold and subsequent hook up and commissioning (not considered in this study).



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· Completion of the 8 pre-drilled wells by installation of tubing, trees and perforation from a semi submersible drilling rig (simultaneous completion and production will not take place at this stage because all wells will be completed and the rig demobilised prior to first gas).

· Subsequent workover and well intervention activities from semi submersible drilling rig or a DSV equipped with a subsea wireline system.

· Intervention on subsea facilities by divers and/or ROV for inspection, maintenance and repair.· Drilling and completion of future 3 wells.· Drilling and completion of additional 3 wells if required and/or installation and hook up of satellite

wells.· Installation of mid-line template and subsequent hook up and commissioning (not considered in

this study).

Dropped object hazards during the initial construction and installation phase for the flowlines and manifold and future phase for the mid-line template are not addressed in this study. Hazards associated with these activities are considered as part of the risk assessment process during detail design. The dropped object and impact criteria for these activities and facilities will be based on the same criteria developed for the subsea facilities.

The study considers the subsea facilities by division into a number of areas, as follows.

· Subsea manifold location.· Infield flowlines and tees.· Platform approaches, SSIVs and risers.

In order to rationalise the number of project phases and facilities under consideration, the following situations are assessed in this study.

· Batch setting and pre-drilling operations of the subsea wells.· Completion and post installation intervention operations on the subsea wells and manifold.· Future drilling operations of subsea wells.· Activities affecting infield flowlines, tees and control umbilicals.· Activities affecting platform approaches, risers and SSIVs pipelines.

1.3 Abbreviations

BOP Blowout PreventorC/T Coiled TubingDSV Dive Support VesselEDP Emergency Disconnect PackageESD Emergency Shut DownFB Full Bore (rupture)LRP Lower Riser PackageOIM Offshore Installation ManagerPSU Power Supply UnitQRA Quantitative Risk AssessmentROV Remote Operated VehicleSAR Safety Action RecordSCSSV Surface Controlled Subsurface Safety Valve (alternatively referred to as a Down Hole

Safety Valve, DHSV)SSIV Subsea Isolation ValveTH Tubing HangerTHRT Tubing Hanger Running ToolTHOAJ Tubing Hanger Orientation and Alignment JointW/L Wireline



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2.0 RECOMMENDATIONS

The recommendations drawn from this study are shown below, each separated into major development stages of the subsea facilities; batch setting and pre-drilling operations, completion and future workover and intervention operations, future drilling operations and general recommendations applicable to all stages of development. All recommendations have been issued as safety action records, SAR SS-011-001 to SS-011-031 inclusive.

2.1 Recommendations for Batch Setting and Pre-Drilling Operations

1. The minimum centre to centre spacing for the trees should be 15m with a ±1m well positioning tolerance. This recommendation is addressed in SAR SS-011-001.

2. During the pre-drilling phase, all subsea wells should be batch set by completing all riserless drilling operations and installing the 36", 30" and 20" casing and wellhead before any wells are fully drilled. This recommendation is addressed in SAR SS-011-002.

3. During the pre-drilling phase, BOP running and retrieval operations, a minimum safe horizontal separation distance of 28m must be maintained between the centre of the rig moonpool and the nearest point on the subsea wells, BOP running and retrieval operations should be carried out outside the 28m dropped object boundary, as shown in Figures 9 and 10. This recommendation is addressed in SAR SS-011-003.

4. During the pre-drilling phase, equipment and materials must be loaded onto the rig at a safe distance from the subsea wells. The minimum horizontal separation distance of either 28m or 42m as given in Table 7 for various types of equipment and materials must be maintained between the path of the load and the nearest point of the subsea wells, as shown in Figures 9, 11 and 12. This recommendation is addressed in SAR SS-011-004.

5. Debris caps should be fitted on all wellheads as soon as they are installed to minimise the time that the wellheads are left unprotected from small dropped objects (tools, etc). This recommendation is addressed in SAR SS-011-005.

2.2 Recommendations for Completion and Future Workover and Intervention Operations

6. During BOP running and retrieval operations, a minimum horizontal separation distance of 28m should be maintained between the centre of the rig moonpool and the nearest point on the subsea wells. BOP running and retrieval operations should be carried out outside the 28m boundary, as shown in Figure 9 and 10. Following installation of the future wells, the modified 28m boundary shown in Figure 9 should be used to determine the minimum safe distance. This recommendation is addressed in SAR SS-011-006.

7. During well completion and future workover and intervention operations, equipment and materials must be loaded onto the rig at a safe distance from the subsea facilities. The minimum horizontal separation distance of either 28m or 42m as given in Table 7 for various types of equipment and materials must be maintained between the path of the load and the nearest point of the subsea facilities, as shown in Figures 9, 11 and 12. This recommendation is addressed in SARs SS-011-007 to SS-011-010 inclusive.

8. Due to the relatively heavy subsea trees (35 tonnes), only rigs with adequate craneage should be used for completion and workover operations during which trees are loaded onto the drilling rig. Wherever possible, rigs which can only load trees to the rear of the vessel should be avoided unless the rig can be moved to the minimum safe distance for tree loading operations. This recommendation is addressed in SAR SS-011-011.

9. In situations where wellheads are left for any significant period of time without a tree installed, debris caps should be fitted to minimise the time that the wellheads are left unprotected from small dropped objects (tools, etc). This recommendation is addressed in SAR SS-011-012.



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2.3 Recommendations for Future Drilling Operations

10. The minimum centre to centre spacing for the trees should be 15m with a ±1m well positioning tolerance. This recommendation is addressed in SAR SS-011-013.

11. All future subsea wells should be batch set by completing all riserless drilling operations and installing the 36", 30" and 20" casing and wellhead before any wells are fully drilled. This recommendation is addressed in SAR SS-011-014.

12. During BOP running and retrieval operations, a minimum horizontal separation distance of 28m should be maintained between the centre of the rig moonpool and the nearest point on the subsea facilities. BOP running and retrieval operations should be carried out outside the 28m boundary as shown in Figure 9 and 10. Following installation of the future wells, the modified 28m boundary shown in Figure 9 should be used to determine the minimum safe distance. This recommendation is addressed in SAR SS-011-015.

13. During future drilling operations, equipment and materials must be loaded onto the rig at a safe distance from the subsea facilities. The minimum horizontal separation distance of either 28m or 42m as given in Table 7 for various types of equipment and materials must be maintained between the path of the load and the nearest point of the subsea facilities, as shown in Figures 9, 11 and 12. This recommendation is addressed in SARs SS-011-016 to SS-011-020 inclusive.

14. Debris caps should be fitted on all wellheads as soon as they are installed to minimise the time that the wellheads are left unprotected from small dropped objects (tools, etc). This recommendation is addressed in SAR SS-011-021.

2.4 General Recommendations for all Drilling and Intervention Activities

15. Anchor handling operations should be carried out at a safe distance from the subsea facilities and where possible anchor handling boats do not traverse the subsea facilities whilst running anchors. Rig mooring procedures should be developed to ensure that appropriate precautions are followed. This recommendation is addressed in SAR SS-011-022.

16. Rig operating procedures should be developed to ensure that anchor touch down zones do not encroach on the subsea facilities. These procedures should address all rig operations under all weather conditions. This recommendation is addressed in SAR SS-011-023.

17. 20' containers should be avoided for the transport of materials or equipment to drilling rigs or other vessels working over the subsea facilities. All goods should be transported in 10' or mini containers where possible. This recommendation is addressed in SAR SS-011-024.

18. Emergency response guidelines should be developed to cope with a dragging anchor to ensure that the mooring chain is released before the dragging anchor impacts subsea facilities. This recommendation is addressed in SAR SS-011-025.

19. Emergency response guidelines should be developed to address potential major accidents such as a sinking rig, a sinking supply boat or a helicopter crashing and sinking adjacent to a vessel near the subsea facilities. A full ESD of the subsea facilities should be initiated under all these circumstances. This recommendation is addressed in SARs SS-011-026 to SS-011-028 inclusive.

2.5 Recommendations for Further Work

20. Dropped object hazards during initial manifold and flowline construction and installation operations and hook up and commissioning activities are to be addressed during detail design. This recommendation is addressed in SAR SS-011-029.

21. Dropped object hazards during future mid-line template construction and installation operations and hook up and commissioning activities are to be addressed during detail design. This recommendation is addressed in SAR SS-011-030.

22. Further analysis should be carried out on 10' and mini containers to determine their stiffness under impact conditions to allow the energy transferred to the subsea facilities to be determined. This recommendation is addressed in SAR SS-011-031.



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3.0 DROPPED OBJECTS AND IMPACTS

The general philosophy adopted for protection of the subsea facilities against dropped object and impact damage is to ensure that no releases or damage critical to production occurs as a result of oil field related activities or fishing operations.

Since fishing operations cannot be controlled with a high degree of confidence, it is acknowledged that physical protection will have to be used to prevent damage. This is a practical solution given the magnitude of forces associated with fishing operations.

By contrast, oil field related activities can be controlled which allows the possibility of protecting against dropped object and impact loads by removing the hazard, rather than by providing physical protection. This allows large dropped object and impact forces that cannot be practically protected against by physical means to be controlled by procedural means to minimise the hazard. For some rig operations (primarily BOP and tree handling) this approach will be used where the rig will be moved over a heavy goods handling area so that no damage to subsea facilities will occur in the event of the BOP being dropped during running and retrieval operations.

One of the key design goals of the subsea facilities is to allow simultaneous drilling and production to take place without undue interruptions to production. This will be achieved by ensuring that the physical protection is sufficient to prevent releases or damage from general dropped object hazards during drilling operations. When heavy handling operations are carried out, the rig will be moved over a heavy goods handling area to eliminate the risk. Where hazards cannot be controlled by these means, production will be shut in to provide the necessary mitigation.

To protect vulnerable interfaces and components which could be damaged at low impact energies, there is unlikely to be a robust solution which can eliminate the risk completely. The only practical approach for these hazards is to take general precautions to ensure that dropped objects are minimised and to ensure that adequate protection is achieved wherever possible.

3.1 Overview of Methodology

The general methodology adopted for this study is; firstly to identify all potential dropped object and impact hazards; secondly to assess their potential to cause releases or critical damage to the subsea facilities; and thirdly to ensure that appropriate measures have been taken to provide physical protection or procedural controls in order to reduce risks to as low as reasonably practical. The general methodology is implemented as follows.

· Review all dropped object and impact scenarios to ensure that all potential hazards have been identified. This is based on the Subsea Hazard Identification and Screening Report (Ref. 2) and a review of other documents that address dropped object and impact hazards for subsea facilities (Ref. 3, 4, 5 and 6). Information on the shipping arrangements for Dril-Quip supplied equipment has also been used to identify potential dropped object scenarios.

· For each identified dropped object or impact hazard, determine the likely impact energy and trajectory of dropped objects.

· For the hazards that exceed the protection provided by the Load Case categories given in the Subsea Facilities Basis of Design (Ref. 7) and the Load Cases for wellheads (see Section 3.1.1), determine suitable protective measures or mitigation to reduce risks to as low as reasonably practical.

· Review the hazards that exceed the dropped object protection incorporated into the design of the subsea facilities.

· Determine requirements for precautionary procedures and shutdown philosophy for simultaneous drilling/intervention and production operations based on the dropped object protection incorporated into the design of the subsea facilities to ensure that risks are reduced to as low as reasonably practical.

3.1.1 Load Case Criteria



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The Load Case criteria defined in the Subsea Facilities Basis of Design are summarised below. For a full definition refer to the Subsea Facilities Basis of Design (Ref. 7).

Load Case A Snag loads on structures from fishing gear up to 500kN, pullover loads on vertically sided pipelines and structures up to 310kN and pullover loads on sloping sided pipelines and structures up to 230kN.Load Case B Impacts on pipelines and structures from 25kJ to 45kJ from fishing gear subject to the relative stiffness under impact of the stationary and moving bodies.Load Case C Impacts from non-deformable dropped objects where up to 2kJ is fully absorbed by the facilities on a maximum grid spacing of 0.15m (where applicable) and up to 20kJ is fully absorbed by the facilities on a maximum grid spacing of 2.5m (where applicable). If no protective grid is used, the above energies shall be dissipated by the stationary body.Load Case D Impacts on structures from deformable dropped objects where the energy distributed is governed by the relative stiffness between the moving and stationary bodies under impact conditions. For impacts from dropped tubulars this shall be taken as 30kJ with an equivalent linear stiffness for the moving body of 14.7MN/m. For impacts from dropped containers a load of 50 tonnes is applied at the impact point, governed by local collapse of the container, plus a further impact of 20kJ from the contents at the same location.

In addition to the Load Case criteria specified in the Subsea Facilities Basis of Design (Ref. 7), further information on the impact resistance of the wellheads is required for to assess the pre-drilling operations. Work has been carried out by the platform template wellhead supplier, ABB Vetco (Ref. 18) to determine the impact resistance of the Vetco SG5 wellhead assembly. This work is also considered to be equally applicable to the Dril-Quip SS10 wellheads used for the subsea wells which has led to the following additional Load Cases.

Load Case E External Impacts up to 50kJ and snag loads up to 500kJ which can be absorbed by the Dril-Quip SS10 wellheads (Ref. 18). Note that critical sealing surfaces within the wellhead cannot withstand this impact energy and are covered in Load Case F.Load Case F Impacts up to 2kJ which will not cause critical damage to sealing surfaces within the wellheads (Ref. 18).

3.1.2 As Built Dropped Object and Impact Protection

The Load Case criteria defined in the Subsea Facilities Basis of Design (Ref. 7) established the design intent for provision of dropped object and impact protection for the subsea facilities. The subsea facilities have been designed to meet these load case criteria, including the manifold structure, bundle towheads, trailheads, mid line tee connection, interconnecting spools and protective spool covers. Verification of these as detailed in structural design calculations for the subsea facilities (Ref. 19 and 20).

3.2 Detailed Hazard Review

There are two principal sources of dropped object and impact hazards associated with the subsea facilities, those from oilfield related activities and those from fishing activities, as follows.

· Objects dropped from drilling rigs, dive support vessels, supply boats and other vessels used for inspection, maintenance and repair activities, and impact loads applied during normal intervention activities. These hazards only occur when there are oilfield vessels working on or near the subsea facilities.

· Loads imposed by fishing gear dragging across or snagging on equipment, flowlines and umbilicals and impacts from trawl boards. These hazards can feasibly occur at any time except when there are oilfield vessels working directly over the subsea facilities.

3.2.1 Review of Subsea Hazard Identification and Screening Study



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The Subsea Hazard Identification and Screening Study (Ref. 2) addresses many of the significant dropped object and impact hazards which are summarised by the Safety Action Records (SARs) raised from the study.

SARs relating to dropped object and impact events are shown below giving the SAR reference number and a brief description of the SAR.

SS-010-032 Consider hazards from dropped BOP in QRA.SS-010-034 Consider hazards from dropped tubulars in QRA.SS-010-036 Consider hazards from dropped trees in QRA.SS-010-038 Consider hazards from miscellaneous dropped objects in QRA.SS-010-040 Consider hazards from dropped objects during supply boat transfer operations in

QRA.SS-010-043 Consider hazards from dropped anchors in QRA.SS-010-046 Consider hazards from a vessel sinking onto subsea facilities in QRA.SS-010-049 Consider hazards from anchor chain impacts in QRA.SS-010-052 Consider hazards from diving bell collisions with subsea facilities in QRA.SS-010-055 Consider hazards from ROV collisions with subsea facilities in QRA.

3.2.2 Dropped Object and Impact Hazards Listing

In addition to the dropped object and impact hazards identified in the Subsea Hazard Identification and Screening Study (Ref. 2), a further review has been carried out in order to identify any other hazards.

This has been carried out by reviewing project documents and other published material, discussions with engineering personnel associated with the Britannia subsea development project and other personnel within the industry. This review has identified additional hazards and been used to expand the definition of hazards described in Section 3.2.1, above. Information on the shipping arrangements for Dril-Quip supplied equipment has also been used to identify potential dropped object scenarios.

This has led to an expanded list of dropped object and impact hazards which is used as a basis for the assessment within this study and is as follows.

1. Dropped BOP during running and retrieval operations.2. Dropped tree during running and retrieval operations and rig loading operations.3. Dropped tubulars during loading, off loading, running and retrieval operations.

· Casing - 36", 30", 20", 13.375", 10.75", 9.625" and 7" (liner) in single lengths and bundles.· Tubing - 5.5", 4.5" in single lengths, multiple lengths and bundles.· Drill pipe - 6.625", 5.5", 5" in single and multiple lengths.· Drill collars - 10", 8", 6.5" in single and multiple lengths.· Drilling and completion riser in single and multiple lengths.

4. Dropped containers during rig loading and off loading operations.5. Typical dropped tools, equipment and other objects during loading, off loading and general vessel

operations.· Rig winch.· Mud pump.· Sledge hammer.· Ancillary structure on rig or vessel (handrail, etc.).



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6. Dropped equipment for wireline and coiled tubing operations.· Wireline control and reel container.· Wireline BOP.· Wireline lubricator.· Coiled tubing control container.· Coiled tubing power supply container.· Coiled tubing reel.· Coiled tubing injector head.· Subsea wireline BOP.· Subsea wireline lubricator.7. Dropped anchors and related impacts.· Dropped anchor during anchor handling operations.· Impact from a broken anchor chain.· Impact from anchor chain at catenary touch down point.· Snag load from dragged anchor.

8. Dropped objects and impacts during intervention operations.· DSV taught wire clump weight.· Diving bell clump weight.· Diving bell collision.· Subsea control pod.

9. Impact from other major accidents.· Impact from a sinking vessel.10. Impacts from fishing activity.· Impact from fishing gear.· Snag load from fishing gear.· Pull over load from fishing gear.

3.3 Dropped Object and Impact Analysis

Dropped object and impact analysis has been carried out for all hazards identified in Section 3.2.2 above to determine the potential impact forces and excursion envelope for dropped objects. A range of techniques have been used based either on previous work, published data or from analysis specific to this study. This is described in the following Sections 3.3.1 to 3.3.10.

3.3.1 Dropped BOP

The BOP can only realistically be dropped during running and retrieval operations whilst drilling a well. The BOP will remain on the rig during the complete drilling or workover programme since it is too heavy to be off loaded onto a supply boat using the rig cranes. If for any reason Refurbishment is necessary during the drilling or workover programme, the rig will be demobilised to port.

The BOP is deployed on the end of the drilling riser and lowered to the seabed whilst additional riser sections are added and made up on the drill floor of the rig. The deployment operation starts by transferring the BOP under drill floor by skidding. The BOP is then picked up on the drilling riser and lowered through the moonpool. The assembly is then held on the spider beams and the derrick hook detached to allow another section of riser to be added. The assembly is then picked up and lowered with the operation being repeated until sufficient riser has been added for the water depth. Retrieval of the BOP is carried out in a reverse sequence of operations.

The BOP could potentially be dropped at any stage during this operation due to the BOP becoming detached from the riser assembly (ie, by parting of a riser joint) or the whole assembly becoming detached from the derrick or spider beams.

The typical weight of a BOP assembly is 140 tonnes and would reach a terminal velocity of approximately 10.5 m/s with a resultant impact energy of 9.7MJ, as shown in Table 1.

It is not practical to provide structural protection that can resist this magnitude of impact force so the only practical means of controlling this hazard is either to avoid dropping the BOP or to ensure that if it is dropped, it will not impact the subsea facilities. Although precautions to avoid dropping the BOP



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will be made, it cannot be guaranteed that the BOP will not be dropped. Hence the solution adopted for Britannia is to ensure that if the BOP is dropped, it will not impact the subsea facilities.

In order to achieve this objective, the BOP running and retrieval operations will be carried out over a heavy goods handling area such that if it is dropped, it cannot impact the subsea facilities. In order to determine the size and location of this heavy goods handling area, dropped object trajectory analysis has been carried out for the BOP.

Two cases exist which may yield the largest extent of the drop out zone. The first case is where the BOP is dropped from the surface and has the greatest potential to be carried by the current before it impacts the seabed, and then topples over. The second case is where the BOP is dropped with a number of riser sections attached and then topples over after impacting the seabed.

The largest extent of the drop out zone is where the BOP is dropped from the surface (and has the greatest potential to be carried by the current before it impacts the seabed) and then topples over after impact. If the BOP is dropped with riser sections attached to the BOP, then the riser is likely to topple after impact. The toppling motion is likely to result in the riser buckling and parting at the connections between riser sections. The behaviour of the riser sections for this scenario has not been addressed specifically in this study but is assumed to have an impact energy less than that of dropped tubulars addressed in Section 3.3.3, below.

The drop out zone for the first case gives a maximum radius of 11m for the initial impact with a probability of between 1 x 10-5 and 1 x 10-6 per drop event, as shown in Figure 1. This is to say that if a BOP is dropped, then the probability that it lands further than 11m from the drop axis is between 1 in 100,000 and 1 in 1,000,000.

After the BOP lands on the seabed, it may topple over and could topple away from the impact point, thereby increasing the potential area of damage. This is a conservative assumption given the seabed soil conditions at the Britannia location, a more likely scenario is that the BOP penetrates the seabed to a depth where it cannot topple over. However, detailed analysis has not been carried out and it is therefore assumed that the BOP can topple over.

The drop out zone assuming the BOP does topple over gives a maximum radius of 23m for an impact probability of between 1 x 10-5 and 1 x 10-6 per drop event, as shown in Figure 1. This is to say that provided the rig maintains a horizontal separation distance of 23m from the centre of the moonpool to the nearest subsea facilities then the risk of damage to the subsea facilities in the event of a BOP being dropped from the sea surface will be below 1 x 10-5 per drop event. As the BOP is run on the riser, the potential drop out zone will be reduced in size because the BOP will have a lesser distance to fall and hence a smaller potential excursion due to current forces.

The results of the BOP trajectory analysis are shown in Figure 1 giving the probability of impact per drop versus horizontal distance between the drop point and edge of target for both the initial impact and toppling after impact.

Conclusions for BOP running and retrieval operations

When determining practical safe handling zones for BOP running and retrieval operations consideration should also be given to rig positioning accuracy and rig surge and sway motions which will tend to increase the desired separation distance. This distance is conservatively estimated to be 5m. Therefore, during BOP running and retrieval operations it is recommended that a minimum horizontal separation of 28m is maintained between the centre of the rig moonpool and the nearest subsea facilities.

The BOP drop out zone relative to the rig is shown in Figure 10. BOP handling zones for the pre-drilling operations and future workover and drilling activities are shown in Figure 9.

Once the BOP has been run and all riser sections are installed, the BOP and riser assembly will be raised to provide adequate clearance between the top of the wellhead and the bottom of the BOP.



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The rig will then be moved by tensioning the appropriate anchors to locate the BOP directly above the well. Once the rig is in the correct position, the riser will be lowered and the BOP mated to the wellhead.

During this operation, the BOP will not impact the tree because there is sufficient clearance but the risk of dropping the BOP cannot be eliminated. However, because the riser system is fully assembled at this stage, the risk of dropping the BOP is significantly reduced.

If the BOP is dropped during this operation, it is most likely to impact the well directly beneath the BOP which is being drilled or worked over. During the pre-drilling phase, there will be no risk of hydrocarbon releases from any wells because these wells will not have been perforated or completed. However, in order to minimise the risk of damage, it is prudent to set the well spacing at a suitable distance to prevent damage to adjacent wells for this scenario. Given the height of a typical BOP assembly is 12m, the minimum distance between wells must be at least 12m to prevent damage and possible release. Therefore it is recommended that the minimum centre to centre spacing for the trees is 15m allowing for a 1m well positioning tolerance and the typical dimensions of the trees. This well spacing has been adopted for the subsea layout as shown in Figure 9.

3.3.2 Dropped Tree

A tree can potentially either be dropped during loading operations from a supply boat or during running and retrieval operations as the tree is installed. Loading operations will take place from a supply boat using the rig crane to load the tree onto the rig prior to completion of the well. Tree installation will be carried out by running the tree on the completion riser using the tree running tool and the LRP/EDP assembly.

The all up weight of the completion riser assembly, lower riser package and tree is similar to that of the BOP and riser assembly and therefore the dropped object impact forces and drop out zones for this scenario are assumed to be the same. The control of these hazards during tree running and retrieval operations are the same as those used for BOP deployment.

For assessment of a dropped tree during loading operations, it is assumed that the weight of a tree alone is approximately 35 tonnes and would reach a terminal velocity of 7 m/s with a resultant impact energy of 1.2MJ if dropped from the sea surface, as shown in Table 1.

It is not practical to provide structural protection that can resist this magnitude of impact force so the only way the hazard can be controlled is either to avoid dropping the tree or to ensure that if it is dropped, then it will not impact the subsea facilities. Although precautions to avoid dropping the tree will be made, it cannot be guaranteed that the tree will not be dropped. Hence the solution adopted for Britannia is to ensure that if the tree is dropped, then it will not impact the subsea facilities.

In order to achieve this objective, the tree loading, running and retrieval operations will be carried out over a heavy goods handling area such that if it is dropped, then it cannot impact the subsea facilities. In order to determine the size and location of this heavy goods handling area, dropped object trajectory analysis has been carried out for the tree.

Since the tree is roughly cuboid, it is unlikely to topple over after the initial impact, unlike the BOP. Therefore, trajectory analysis for the dropped tree only includes the initial impact. The drop out zone for the first case gives a maximum radius of 20m which will ensure that if the tree is dropped from the surface, then it will always land within this area. Provided the rig maintains this horizontal distance from the centre of the moonpool to the nearest subsea facilities then there is no risk of damage.

The drop out zone for the tree gives a maximum radius of 20m for the initial impact with a probability of between 1 x 10-5 and 1 x 10-6 per drop event, as shown in Figure 2. This is to say that if a tree is dropped during loading, then the probability that it lands further than 20m from the drop axis is between 1 in 100,000 and 1 in 1,000,000.



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The results of the dropped tree trajectory analysis are shown in Figure 2, giving the probability of impact per drop versus horizontal distance between the drop point and edge of target for the initial impact.

Conclusions for tree loading operations

When determining practical safe handling zones for tree loading operations, consideration should also be given to rig positioning accuracy and rig surge and sway motions which will tend to increase the desired separation distance. This distance is estimated to be 5m. The position of the supply boat, the position of the rig crane and the way in which the crane swings the load onto the rig will also affect the separation distance between the safe handling areas and the subsea facilities. It is recommended that a minimum horizontal separation of 25m is maintained between the path of the tree during loading operations and the nearest subsea facilities.

In order to rationalise the requirement for heavy goods handling zones, the required separation distance of 25m for tree loading operations has been combined with the required separation distances for loading 10" drill collars (see Section 3.3.3) and general heavy equipment (see Section 3.3.5). This has resulted in a general purpose 28m dropped object boundary for loading operations, as shown in Figure 9.

The use of a rig that loads trees at the rear of the vessel is undesirable for the well completion and tree installation phase since this will require the rig to be moved further away from the seabed facilities during tree loading operations. Therefore, it is recommended that rigs on which trees must be loaded at the rear of the vessel are avoided for the well completion and tree installation operations. Of the 26 rigs identified for Britannia (see Section 4.1), only 2 rigs, the Sonat John Shaw and the Western Oceanic Western Pacesetter IV load trees exclusively at the rear of the vessel (Ref. 11) and should be avoided for these activities. Note also that the subsea trees are relatively heavy (35 tonnes) and consideration should be taken of the crane capacity when selecting a rig for well intervention operations during which trees need to be loaded.

3.3.3 Dropped Tubulars

A wide range of tubulars can potentially be dropped during drilling and workover operations when loading onto the rig or during running and retrieval operations. During loading (or off loading) operations from a supply boat, the tubulars will be lifted in a horizontal attitude either as single tubes or as bundles of tubes depending on their size and weight and could potentially be dropped into the sea.

During running and retrieval operations, the tubulars will be handled vertically in the derrick and could potentially be dropped through the moonpool, either as single joints or as multiple joints. Tubulars that are commonly handled in multiple lengths in the derrick include riser, drill pipe, drill collars and tubing. The likelihood of tubulars being dropped vertically from the derrick is less likely than during loading operations. For tubulars to be dropped through the moonpool, there must be an open path from the drill floor to the sea. This only realistically occurs when running riser or during riserless drilling operations. Once the riser is in place, there is no open path from the drill floor to the sea and the likelihood of this occurring is considerably reduced. If tubulars are dropped from the derrick when a riser is in place, then the tubular could fall down the riser. This will not affect the subsea facilities but may necessitate remedial drilling operations.



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In order to assess the potential trajectory and resulting impact energy from dropped tubulars, analysis has been carried out for all tubular items identified in Section 3.2.2 using a commercial software package, DELTA (Ref. 8, 9 and 10). DELTA simulates the trajectory of dropped objects in two dimensions as they fall through the air, then impact the sea surface and then through the water until they reach the seabed. The results provide information on the excursion of the dropped object, it's velocity and orientation.

The simulations have been carried out assuming that tubulars are dropped from a height of 25m above the sea surface at a range of orientations from horizontal to vertical in 10° increments. The current velocity of the water column has been assumed to be 0.66 m/s which corresponds to a return period in excess of 100 years. It is unlikely that drilling or handling operations would take place in current conditions in excess of this since rig operations would be stopped due to the severe weather conditions that are associated with high current velocities and is therefore the limiting case. Full details of the input parameters for the simulations and corresponding results are given in Tables 4 to 6.

This analytical work carried out on the behaviour of dropped tubulars as they fall through the water column indicates that it is extremely unlikely that the tubulars will arrive at the seabed in a vertical orientation. In order to confirm this general finding, additional simulation work was carried out on 10" drill collars to determine the range of initial conditions that would result in the tubular arriving at the seabed vertically. Single lengths of drill collar will only arrive at the seabed vertically if the drill collar is dropped vertically to within approximately ± 1 x 10-6 degrees and the water column is perfectly still (i.e., no current and no waves). These results are shown in Figure 3. These results confirm the general conclusion that all single length tubulars will adopt a horizontal attitude as they fall through the water column and the likelihood of vertical impacts is so low it can be ignored.

If multiple lengths of tubulars are dropped, then they will have to fall further through the water column before adopting a horizontal attitude. The work carried out for multiple lengths of tubulars indicates that when dropped vertically, the tubular string will not have reached a stable horizontal orientation before reaching the seabed. This is not a significant cause for concern because it is assumed that multiple lengths of tubulars can only be dropped through the moonpool during riser running and retrieval operations or during riserless drilling, as discussed above.

In most cases, the tubulars assessed in this study adopt a horizontal attitude whilst falling through the first 50m of the water depth and then continue in a horizontal attitude until they reach the seabed. Results from the DELTA simulation work indicate that all tubulars under consideration dropped as single lengths or in bundles arrive at the seabed within an angle of ± 2.15° to the horizontal. Therefore, for the purpose of impact assessment, it is assumed that all impacts are from horizontal tubulars.

The horizontal distance the tubulars travel as they fall through the water column is dependant on the size of the tubulars and the current velocity. More slender, smaller diameter tubulars tend to travel further whilst larger diameter tubulars tend to travel shorter distances. This phenomena occurs because after motions of the dropped tubular stabilise to a horizontal orientation, the tubular is accelerated up by the current so that the horizontal velocity is the same as the current velocity. The horizontal distance travelled is then determined by the vertical velocity relative to the current velocity. Since larger diameter, heavier tubulars tend to fall vertically through the water column faster than smaller diameter, lighter tubulars they will not travel so far from the drop point.

Results from the DELTA simulation work for the maximum horizontal excursion distance at the seabed are shown in Tables 4 to 6. These results indicate that the maximum excursion distance for single lengths of 30" conductors is approximately 33m which increases up to approximately 75m for 4½" tubing. Note that these results have been obtained from a range of 10 simulations at different drop angles and therefore do not represent the maximum potential excursion that could occur which may be greater at some intermediate angle or different wave conditions. However, the variability in the results at the different drop angles indicates that the maximum horizontal excursions are unlikely to be exceeded by more than 10% for the same current conditions.



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The DELTA simulation results summarised in Table 1 show the predicted horizontal excursion distance, impact velocity, and impact energy for each of these tubulars. Where appropriate, results are also given for bundles and multiple lengths of these tubulars. The effect and mitigation of each of these hazards for impacts on unprotected and protected pipework is given in Tables 2 and 3 respectively.

Over the course of the drilling and intervention activities on the subsea facilities, different hazards will occur over the different phases of the project. Some tubulars used are unique to specific phases which limits the possible hazards over the different phases. These are summarised as follows.

TubularDescription

Pre-Drilling Operations

Completion &Workover

Operations

Future Drilling & Completion of

Additional Wells36" Casing Yes No Yes30" Casing Yes No Yes20" Casing Yes No Yes13.375" Casing Yes No Yes10.75" Casing Yes No Yes9.625" Casing Yes No Yes7" Liner Yes No Yes5.5" Tubing No Yes Yes4.5" Tubing No Yes Yes6.625" Drill Pipe Yes No Yes5.5" Drill Pipe Yes Yes Yes5" Drill Pipe Yes Yes Yes3.5" Drill Pipe No Yes Yes10" Drill Collar Yes No Yes8" Drill Collar Yes No Yes6.5" Drill Collar Yes Yes YesDrilling Riser Yes Yes YesCompletion Riser No Yes Yes

For single lengths of tubulars dropped from the rig, the impact energies and horizontal excursion distances are as follows.

Description Impact Energy(kJ)

Horizontal Distance Travelled (m)

36" Casing (single) 133 3330" Casing (single) 87.6 3320" Casing (single) 24.4 4410" Drill Collar (single) 49.2 22

For multiple lengths of tubulars dropped from the rig, the impact energies and horizontal excursion distances are correspondingly higher, as follows.

Description Impact Energy(kJ)

Horizontal Distance Travelled (m)

Drilling Riser (length x 2) 51.4 6810" Drill Collar (length x 4) 299 508" Drill Collar (length x 4) 183 606.5" Drill Collar (length x 4) 78.4 70



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Given the large potential drop out area for tubulars, it is not practical to control all tubular dropped object hazards by performing all lifting operations over a heavy goods handling area. Therefore, it is preferable to ensure that the physical protection of the subsea facilities is sufficient to resist the resultant impact forces and prevent damage to equipment and subsequent hydrocarbon releases.

Conclusions for dropped tubular risks during batch setting and pre-drilling operations

For the pre-drilling operations, additional precautions need only be considered for dropped objects which exceed the 50kJ impact energy for Load Case E. Load Case F is not considered applicable for dropped tubulars since the internal wellhead seal surfaces will not be affected by horizontal impacts from tubulars.

Single lengths of dropped 36" and 30" casing and multiple lengths of drill collars exceed Load Case E and therefore a means of mitigating against these impacts should be considered.

The potential impact energy of 51.4kJ for dropped dual lengths of drilling riser only just exceeds the allowable impact energy of 50kJ for load case E. The total energy of 51.4kJ will not be transferred to the wellhead in practice because some energy will be dissipated by flexing of the riser on impact, thereby reducing the impact energy transferred to less than 50kJ.

An obvious solution to minimising these dropped object risks during the pre-drilling phase would be to complete all riserless drilling on all wells before drilling for the 13.375" casing is started. With this strategy, all handling operations for the 36" and 30" casing and drill collars (which are most likely to be dropped during riserless drilling) are completed before riser drilling starts. If a 36" casing, 30" casing or drill collar is dropped during this phase then the maximum remedial cost is likely to be one well being re-drilled and 36", 30" and 20" casing installed, say 10 days rig time. Conversely, if all wells are drilled in strict sequence, the maximum remedial cost is likely to be a complete well at approximately 75 days rig time.

The recommendations to minimise the risk of damage from dropped tubulars are therefore to carry out all riserless drilling operations on all wells and install the 36", 30" and 20" casing. Following these operations, the main drilling operations for each well should be completed in sequence. This strategy will minimise the potential cost and duration of remedial work in the event of a dropped tubular critically damaging a well.

During the initial batch setting operations of the pre-drilling phase, there is no risk of hydrocarbon release since there are no wells drilled at this stage. However, loading of the 36" and 30" casing could result in damage to the wellheads which have been batch set or drilled if casing is dropped during loading operations. Although mitigation could be provided by moving the rig to a heavy goods handling area during the loading operations, each rig move is likely to take at least 4 hours and it is arguable that this strategy will provide any benefit.

Given that the worst case scenario for a dropped length of 36" or 30" casing would result in a severely damaged wellhead resulting in the well being abandoned, this would only incur 10 days extra rig time to batch set a new well and install the 36", 30" and 20" casing. On this basis, moving the rig to a safe loading area can only be justified if the probability of dropping a length of 36" or 30" casing is greater than the risk adjusted cost of remedial work. This can be approximated as follows.

If P PT

Tdrop hitload

drill Then move rig to heavy goods handling area to load 36" and 30"

casing.

Where Pdrop = The probability of dropping the 36" or 30" casing.

Phit = The probability of a wellhead being hit by the 36" or 30" casing.

Tload = The time taken to move the rig to loading area.

Tdrill = The time taken to re-drill the well assuming it is abandoned.



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Historical data indicates that the probability of dropping a length of 36" or 30" casing during loading operations (ie, Pdrop) is approximately 1 x 10-3 per lift operation (Ref. 17). The probability of a well

being hit (ie, Phit) can be approximated to the cross sectional area of the tubular over the drop out

area which is approximately 1 x 10-2 per drop event assuming there is one well that can be hit.

Over the batch setting operations, the number of wells that can potentially be hit will increase from zero (during the lifting operations for the first well) to 7 (during the lifting operations for the last well). Therefore, the expression for Pdrop x Phit will increase from zero to 0.0007 over the course of the

batch setting operations. Over this period, the expression T load over Tdrill will remain constant at

0.01667. Since Tload over Tdrill is always greater than Pdrop x Phit, moving the rig to the heavy goods

handling area is not justified for loading the 36" and 30" casing.

The same argument can be applied to any dropped object precautions considered for multiple lengths of drill collars. The probability of dropping a multiple length of drill collars (ie, Pdrop) will be lower than

that for 36" and 30" casing and the probability of a well being hit hitting (ie, Phit) will also be lower due

to the smaller cross sectional area and larger drop out zone for the drill collars. Therefore moving the rig to a heavy goods handling area is not justified for drill string running operations.

Conclusions for completion and post installation workover and intervention operations

Although impact forces from dropped 36", 30" and 20" casing sections exceed Load Cases C and D, these tubulars will not be handled during completion or post installation workover and intervention operations. Therefore, these hazards need not be considered for these phases of the development.

During running and retrieval operations, tubulars will be handled vertically in the derrick and could potentially be dropped through the moonpool, either as single joints or as multiple joints. Tubulars that are commonly handled in multiple lengths in the derrick include drilling riser, completion riser, drill pipe, drill collars and tubing. The likelihood of tubulars being dropped vertically from the derrick is less likely than during loading operations. For tubulars to be dropped through the moonpool, there must be an open path from the drill floor to the sea. This only realistically occurs when running riser or during riserless drilling operations. Once the riser is in place, there is no open path from the drill floor to the sea and the likelihood of this occurring is considerably reduced. If tubulars are dropped from the derrick when a riser is in place, then the tubular could fall down the riser. This will not affect the subsea facilities but may necessitate remedial drilling operations.

Of these tubulars, only dual lengths of drilling riser exceed Load Cases C and D which are only likely to be dropped during BOP running and retrieval operations when the rig is located over the BOP handling area. Although the 28m separation for the BOP handling zone is insufficient to eliminate the risk of a dual length of drilling riser impacting the subsea facilities (drop out radius 68m), the risk of impact will be reduced considerably. Increasing the separation distance from 28m to 68m will give a reduction in risk, this is not considered significant and therefore no additional precautions are considered necessary.

Conclusions for future drilling operations of subsea wells

When drilling the 3 future subsea wells that will have 36", 30" and 20" casing installed during the initial batch setting operations, hazards from dropped tubulars will be the same as during the initial pre-drilling phase. However, at this stage of the development, the initial 8 subsea wells, manifold and flowlines will be installed and hence the consequences of dropped objects more severe. Ideally, these drilling operations will be carried out simultaneously with production from the existing 8 subsea wells. However, since these operations will be planned for the summer months, a production shutdown may have no economic impact depending on the sales contract and the status of platform production.

During simultaneous drilling/workover and production, the layout of the subsea facilities will have a significant impact on the risk and potential consequences of a release due to a dropped tubular. If it is not feasible to protect all hydrocarbon systems by providing adequate separation, then it is



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preferable to place those systems that contain the largest inventory as far from the drop point as possible. Releases from trees and jumper hoses can be isolated by shutting in the well and manifold valves, thereby limiting the release. Conversely, it will not be possible to isolate releases from the flowlines and therefore greater emphasis should be placed on ensuring that the flowlines are well outside possible drop out areas.

The same strategy used for pre-drilling activities of completing all batch setting operations prior to drilling the wells should be followed for the future wells. This will minimise the dropped object risk and remedial activities for the new wells. In addition to this, the 36", 30" and 20" casing and 10" drill collars should be loaded over a heavy goods handling area such that if they are dropped, they cannot impact the existing subsea wells, manifold and pipelines. This strategy will allow production from the existing wells to continue during the drilling operations provided there are no other overriding safety considerations.

During these loading operations, the rig should be located far enough from the existing subsea wells, manifold and flowlines such that the drop out zones for the respective tubulars does not encroach onto the subsea facilities. The drop out zones relative to the generic rig is shown in Figures 11 and 12.

3.3.4 Dropped Containers

During drilling and intervention operations on the subsea facilities, general supplies, equipment and materials will be transferred to rigs and other surface support vessels in containers. 3 types of container are generally used offshore, small mini containers (2.3m x 1.85m x 1.6m) weighing up to 6 tonnes fully loaded, 10' containers (3m x 1.8m x 1.8m) weighing up to 8 tonnes fully laden and large 20' containers (6.1m x 2.5m x 2.5m) weighing up to 18 tonnes fully laden.

Containers are generally transferred between supply boats and rigs (or large DSVs) using the vessel cranes and could potentially be dropped during this transfer process. Once on the rig or vessel, they are not generally moved and are secured to prevent them being swept overboard in severe weather.

In order to assess the potential trajectory and resulting impact energy from dropped containers, analysis has been carried out on the three types of container both in the full (loaded) and empty condition. For the full condition, two cases have been assessed, firstly where the weight of the contents are evenly distributed (such that the centre of gravity is at the centre of the container); and secondly where centre of gravity is displaced towards one end of the container. This second case is based on the assumption that the contents of the container is a solid cube of steel of the required weight and this falls to one end on impact with the water. This causes the container to fall through the water in a vertical orientation which results in the maximum velocity through the water.

This case is not likely to occur in practice because the contents of the containers are often secured and in practice, the bulk of the contents would not allow a sufficient shift in the centre of gravity to make the container hydrodynamically stable in the vertical orientation. Also, it is common practice to evenly load the containers and secure the contents if they are likely to shift in transit. Therefore, it has been assumed that containers will fall in a horizontal attitude. However, results for vertical orientations are given for information.

The simulations have been carried out assuming that containers are dropped from a height of 25m above the sea surface at a range of orientations from horizontal to vertical in 10° increments. The current velocity of the water column has been assumed to be 0.66 m/s which corresponds to a return period in excess of 100 years. It is unlikely that container handling operations would take place in these conditions and is therefore the limiting case. Full details of the input parameters for the simulations and corresponding results are given in Table 4 to 6.

Results from the DELTA simulation work for dropped containers are shown in Table 1 and summarised below. These results indicate that provided the load in the container is evenly distributed, the container will adopt a horizontal attitude, irrespective of the angle which it is dropped from. Provided the centre of gravity of the containers is located along the longitudinal centre line of the container, they will always arrive at the seabed within an angle of ± 0.67° to the horizontal.



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DescriptionWeightin Air(kg)

HorizontalDistance

Travelled (m)

ImpactEnergy

(kJ)Mini Container Empty 1,620 60 37.6Mini Container Full 6,000 30 15310' Container Empty 2,000 66 49.910' Container Full 8,000 31 21420' Container Empty 3,000 117 21120' Container Full 18,000 39 635

Note that these results have been obtained from a range of 10 simulations at different drop angles and therefore do not represent the maximum potential excursion that could occur which may be greater at some intermediate angle or different wave conditions. However, the variability in the results at the different drop angles indicates that the maximum horizontal excursions are unlikely to be exceeded by more than 10% for the same current conditions.

The horizontal excursion distances shown in the results above assume that the containers sink immediately on entering the water. In practice, all the containers under consideration would float, even when fully loaded. However, they would slowly sink as they became flooded with water through the ventilation ports. It is not possible to predict the time that a container would remain afloat before sinking, during which time currents could carry the container a considerable distance from the drop point. Historical evidence suggests that containers have floated and been carried for up to 15km before sinking. Historical evidence also suggests that the doors of the container could burst open on impact with the sea surface, in which case the container would start sinking almost immediately. The relationship between the distance the container drifts and the probability of impacting seabed facilities quickly diminishes with distance. This relationship is shown in Figure 4. At a distance of 1,000m from the drop point, the probability of impact drops to between 1 x 10-5 and 1 x 10-6.

20' containers may be used on the platform although they are used infrequently. Information obtained from the Murchinson platform (Ref. 12) indicates that mini containers account for over 90% of movements, 10' containers for less than 10% and 20' for less than 1%. It is not possible to eliminate the use of 20' containers on platforms since they are needed for bulky spare parts and equipment. However, at the platform, potential damage from dropped 20' containers can be protected against by providing adequate separation. This is feasible for the platform because separation distances are greater than at the subsea locations.

Conclusions for dropped container risks

The potential impact energy from a dropped container is significant and exceeds the basic Load Case criteria (Ref. 7). However, in the event of an impact from a container, a considerable proportion of the available energy would go into deforming the container, rather than damaging the seabed facilities that are hit. It is recommended that impact analysis is carried out for 10' and mini containers to determine the energy transferred to the subsea facilities under impact conditions.

Impact forces associated with 20' containers cannot be practically protected against. Given the infrequent use of 20' containers on drilling rigs, it is recommended to avoid their use wherever possible for the regular transport of equipment and materials and transfer all goods in smaller 10' containers.

In order to minimise the risk of damage from dropped containers it is recommended that 20' containers are not transferred between the rig and supply vessels when on location over the subsea facilities and that all goods are transferred in mini and 10' containers. Given the infrequent use of 20' containers for the regular transport of equipment and materials on drilling rigs, this recommendation is unlikely to cause any significant operational constraints. Note that 20' containers may be used for 'company stores' in which case they will be loaded onto the rig before mobilisation and will not be off loaded until rig demobilisation.



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3.3.5 Dropped Tools, Equipment and Other Objects

This section covers miscellaneous tools, equipment, consumables and other objects that could be dropped from vessels positioned over the subsea facilities. Potential dropped objects addressed in this section include equipment and spare parts for the rig or vessel, tools and ancillary structures on the rig or vessel that could become detached. This is not intended to be an assessment of all possible dropped objects in this category but a representative sample of typical tools, equipment and other objects which can be dropped.

These objects could be dropped either during loading from a supply boat or from the vessel during normal activities or lost during rough weather. The potential trajectory and resulting impact energy for this equipment has been obtained from published data (Ref. 4 and 5). Results from the predicted trajectories and impact energies are shown in Table 1 and summarised below.


HorizontalDistance

Travelled (m)

ImpactEnergy

(kJ)Rig Winch 25,000 20 450Mud Pump 33,000 20 810Sledge Hammer 5 8 2Ancillary Structure on Vessel 500 20 12

These results indicate that the potential impact energy from a large piece of equipment that is dropped from the rig could cause major damage. These hazards will therefore have to be protected against by procedural controls.

Conclusions for dropped tools, equipment and other objects

It is recommended that large items of equipment such as spare winches and mud pumps for the rig or other vessels are loaded over heavy goods handling area at a safe distance from the subsea facilities. When determining practical safe handling zones for these loading operations, consideration should also be given to rig positioning accuracy and rig surge and sway motions which will tend to increase the desired separation distance. This distance is conservatively estimated to be 5m. Therefore, during loading operations for large items of equipment it is recommended that a minimum horizontal separation of 28m is maintained between the path of the load and the nearest point on the subsea facilities. The 28m dropped object boundary is shown in Figure 9.

For the pre-drilling operations, impact energies associated with dropped tools (sledge hammer) and ancillary structures such as a section of hand rail or temporary walkway and other similar small dropped objects generally exceed Load Case F. Given the small size of these objects, they could easily damage wellhead sealing surfaces. The debris caps on the wellheads would provide adequate protection against these dropped objects so risks can be minimised by ensuring that the debris caps are installed on all wellheads except the well which is being drilled.

For other operations where the wellhead is not exposed, impact energies associated with dropped tools (sledge hammer) and ancillary structures such as a section of hand rail or temporary walkway are within the criteria for Load Case C (Ref. 7), therefore no additional protection is required.



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3.3.6 Dropped Equipment for Wireline and Coiled Tubing Operations

During drilling and workover operations, it will be necessary to employ wireline and coiled tubing techniques to carry out downhole operations. Wireline operations will normally be carried out from a drilling rig as part of the drilling and workover programme for such tasks as installing plugs, surveying and logging wells. A subsea wireline lubricator system may also be used, deployed from a DSV to carry out logging and installing wireline insert SCSSVs. Coiled tubing operations will be carried out from a drilling rig to support drilling and workover operations.

Wireline and coiled tubing equipment used on rigs is generally hired in for the duration on the work and is packaged to allow easy transport to the field. A wireline system generally comprises of 3 packages, a wireline control and reel container, wireline BOP and wireline lubricator. A coiled tubing system generally comprises of 4 packages, a coiled tubing control container, coiled tubing power supply unit (PSU) container, coiled tubing reel and coiled tubing injector head. Note that for the pre-drilling activities a wireline system will be loaded onto the rig prior to mobilisation and will remain on the rig for the duration of the pre-drilling programme.

The potential trajectory and resulting impact energy for this equipment if it is dropped has been assessed for all items using the DELTA software package (Ref. 8, 9 and 10). The simulations have been carried out assuming that items are dropped from a height of 25m above the sea surface at a range of orientations from horizontal to vertical in 10° increments. The current velocity of the water column has been assumed to be 0.66 m/s which corresponds to a return period in excess of 100 years. It is unlikely that loading operations would take place in conditions and is therefore the limiting case. Full details of the input parameters for the simulations and corresponding results are given in Table 6.

Results from the DELTA simulation work indicates that provided the wireline and coiled tubing containers are evenly loaded, they will adopt a horizontal attitude, irrespective of the angle which they are dropped from. Provided the centre of gravity of the containers is located along the longitudinal centre line of the container, they will always arrive at the seabed within an angle of ± 1° to the horizontal. This is a valid assumption because the contents of these containers are permanently installed and secured inside the container with weight evenly distributed to simplify lifting operations. Results from the DELTA simulation work are shown in Table 1 and summarised below.


HorizontalDistance

Travelled (m)

ImpactEnergy

(kJ)W/L Control & Reel Container 5,000 64 90.6W/L BOP 1,000 22 13.8W/L Lubricator 900 54 5.7C/T Control Container 5,500 61 101C/T PSU Container 6,950 56 132C/T Reel 11,500 44 161C/T Injector Head 5,400 52 157Subsea W/L BOP 1,000 N/A 13.8Subsea W/L Lubricator 900 N/A 5.7

Note that these results have been obtained from a range of 10 simulations at different drop angles and therefore do not represent the maximum potential excursion that could occur which may be greater at some intermediate angle or different wave conditions. However, the variability in the results at the different drop angles indicates that the maximum horizontal excursions are unlikely to be exceeded by more than 10% for the same current conditions.

The impact energies associated with the wireline and coiled tubing containers do not exceed that given for a fully loaded 10' container (214kJ) in Section 3.3.4 and therefore this should be taken as the worst case dropped container (maximum total impact energy). However, the relative stiffness of the wireline and coiled tubing containers will have to be taken into consideration when assessing the total energy transferred to the subsea structure on impact. The horizontal excursion distances shown



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in the results above assume that the containers sink immediately on entering the water. In practice, all the containers under consideration would float, even when fully loaded. However, they would slowly sink as they became flooded with water through the ventilation ports. It is not possible to predict the time that a container would remain afloat before sinking, during which time currents could carry the container a considerable distance from the drop point.

Impacts from dropped subsea wireline equipment are only likely to impact the well that is being worked on since the subsea wireline BOP and subsea lubricator are run on guidewires. If they are dropped during the subsea wireline intervention operation then it is only possible for the objects to fall down the guidewires.

Conclusions for dropped wireline equipment

The potential impact energy from a dropped wireline control and reel container is significant and exceeds the basic Load Case criteria (Ref. 7). However, in the event of an impact, a considerable proportion of the available energy would go into deforming the container, rather than damaging the seabed facilities that are hit. It is recommended that impact analysis is carried out for wireline containers to determine the energy transferred to the subsea facilities under impact conditions.

The potential impact energy from a dropped wireline BOP or wireline lubricator are less than that given for Load Case C and therefore adequate protection against these items is provided.

Conclusions for dropped coiled tubing equipment

The potential impact energy from dropped coiled tubing control and PSU containers is significant and exceeds the basic Load Case criteria (Ref. 7). However, in the event of an impact, a considerable proportion of the available energy would go into deforming the container, rather than damaging the seabed facilities that are hit. It is recommended that impact analysis is carried out for coiled tubing containers to determine the energy transferred to the subsea facilities under impact conditions.

Potential impact energies from a dropped coiled tubing reel and injector head exceed the basic Load Case criteria (Ref. 7). It is recommended that these items are loaded over the heavy goods handling area at a safe distance from the subsea facilities.

3.3.7 Dropped Anchors and Related Impacts

When semi-submersible drilling rigs are working on the subsea wells, it will be necessary to moor the rig using anchors. Smaller vessels may also be moored over the subsea facilities but this will depend on the type of vessel and the nature and duration of the work. It is anticipated that dive support vessels will predominantly use dynamic positioning when performing intervention activities which is discussed in Section 3.3.8, below.

A number of potential dropped object and impact hazards are associated with vessel mooring, as follows.

· Dropped anchor during anchor handling· Impact from a broken anchor chain· Impact from anchor chain at catenary touch down point· Snag load from dragged anchor

If a drilling rig or similar anchor is dropped during deployment or recovery, then the potential impact energy will be approximately 90kJ. Although it is possible to provide protection for subsea facilities against this magnitude of impact force, it would result in large protective structures. Pipelines could not practically be protected against this magnitude of impact because the majority of the impact energy will be absorbed by deformation of the seabed facilities that are hit.

The solution adopted for this scenario is to ensure that all anchors are handled during running and retrieval a safe distance away from the seabed facilities such that if an anchor is dropped, then it will not impact the subsea facilities. The anchor handling vessel may have to carry anchors over



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pipelines which may not be avoidable. The layout of seabed facilities discussed in Section 4.0 considers anchoring procedures and it is anticipated that the layout will allow all anchor transfer operations to be carried out away from the subsea facilities.

It is anticipated that a precautionary process shutdown of the subsea facilities will not be necessary during vessel anchoring operations. However, these issues will be addressed when detailed mooring procedures are developed.

Whilst a rig is moored over the subsea facilities, it is possible that a failure may occur in the mooring line which would result in the anchor chain (or cable) falling to the seabed. This is likely to occur during severe weather when high anchor line tensions are experienced. The most likely point of failure is at the fairleader on the rig since this is usually the point of maximum tension.

If an anchor chain should part in such circumstances, then the chain will drop to the seabed and could potentially damage the subsea facilities. However, the impact mechanism in such an event will be a series of small impacts as each link in the chain falls to the seabed, in a line defined by the catenary shape of the chain at the instant before failure . The maximum impact energy will be governed by the size and weight of the individual chain links and the velocity of the chain as it falls to the seabed. It has been assumed that the maximum individual impact energy associated with this event is within the criteria for Load Case C (Ref. 7). After impact, the dead weight of the chain will apply a load at the resting point of the chain. This is assumed to be within allowable limits based on the assumption that the chain will come to rest along a line and will not be concentrated at one point.

Whilst a rig is moored over the subsea facilities, the anchor chain will repeatedly impact the seabed in the touch down zone as environmental forces on the rig are absorbed by the mooring system. The touch down zone varies with the type of mooring system used on the rigs and anchor tensions applied during rough weather. Although these impacts from the anchor chain are within the impact criteria for Load Case C (Ref. 7), repeated impacts at the same point are likely to cause damage, particularly to the carrier pipe of the heated flowlines.

This issue has been addressed by sending a questionnaire to rig owners to obtain further information of mooring system characteristics (Ref. 11). The responses obtained on this subject varied considerably due partly to the way in which the question was interpreted by the rig owners and the level of detail available from the mooring analyses. Mooring analyses carried out by the rig owners varied from standard static catenary tables to full dynamic analyses under storm survival conditions and dynamic cases for broken anchor lines.

From the responses obtained, only those from Diamond and Saipem give full dynamic analyses in sufficient detail to establish a realistic touch down radius under storm survival conditions. In order to derive generic touch down zones for the Britannia development, this information has been further assessed to take account of rig movements and differences in the co-ordinate systems used by Diamond and Saipem. Results from this assessment (Ref. 11) indicate that under storm survival conditions (when the rig will be located over the centre of the seabed facilities), the minimum touch down distance occurs on the leeward anchors which can touch the seabed as close as 15m horizontally from the fairleader.

During normal operations, the intention is to keep the rig precisely located over the subsea facilities which is achieved by increasing anchor tensions. During rough weather (storm survival conditions), the intention is to ride out the storm without exposing the anchors to excessive tensions by slackening off the mooring system.



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When anchor tensions are reduced, more anchor chain is placed on the seabed which is lifted to absorb rig motions due to wind and wave action. This gives the worst case condition that results in the touch down zones which occurs on the leeward anchors which can touch the seabed as close as 15m from the fairleader. The typical rig locations under storm survival conditions is shown in Figure 13.

Further correspondence with rig owners (Ref. 13 to 16) recommends that the rig be positioned relative to the subsea facilities in storm conditions such that the touchdown zone of the leeward anchors is clear of the subsea facilities. Rig owners also recommend that the rig be positioned symmetrically across the pipelines to avoid anchor chain impacts on the pipelines under storm survival conditions. Following further clarification with rig owners (Ref. 13 to 16), it is assumed that there is no problem maintaining a 250m touch down radius under normal operating conditions for all rigs under consideration.

Snag loads from dragged anchors are only limited by the breaking strength of the anchor chains or cable. These loads can reach 3.75MN which cannot be tolerated by the design. If such an incident occurred then it would result in hydrocarbon releases and severe damage to the subsea facilities if they were hit by the dragging anchor. However, there would be no immediate impact to personnel on the rig from the hydrocarbon release because the incident would only likely occur in severe weather if the rig is blown off station. The rig would be over 1km downwind of the dragging anchor and the rupture point. The severity of damage could be minimised by appropriate marine and emergency response procedures to avoid the dragged anchor impacting the subsea facilities by releasing the anchor chain before impact.

Conclusions for dropped anchors and related impacts

To avoid potential damage from dropped anchors during running and retrieval operations, it is recommended that anchors are handled a safe distance from the subsea facilities and where possible anchor handling boats do not traverse subsea facilities whilst running anchors. Rig mooring procedures should be developed to ensure that appropriate precautions are followed.

Load Case C criteria (Ref. 7) provides adequate protection against damage from a broken anchor chain.

It is recommended that rig operating procedures are developed to ensure that potential touch down zones do not encroach on the subsea facilities. Responses from rig owners (Ref. 13 to 16) indicate that use of such procedures is feasible but a thorough set of procedures for all operating conditions will have to be developed to ensure protection of the subsea facilities under all conditions.

It is recommended that emergency response procedures are developed to cope with a dragging anchor to ensure that the mooring chain is released before the dragging anchor impacts subsea facilities.

3.3.8 Dropped Objects and Impacts during Intervention Operations

During intervention operations on the subsea facilities for inspection, maintenance and repair, a surface vessel will be located over the subsea facilities in order to deploy divers or an ROV. The type of vessels used for these operations could range from a large well service and dive support vessel (such as the Stena Seawell) to a smaller monohull ROV support vessel. In practice, the type of vessel used will depend on the work to be carried out, the time of year and commercial factors. However, it is anticipated that all ROV and diver intervention operations will be carried out from a dynamically positioned vessel which avoids the need to set anchors.



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A number of potential dropped object and impact hazards are associated with intervention operations, as follows.

· Impact from dropped DSV taught wire clump weight (small and large)· Impact from a diving bell collision· Impact from diving bell clump weight· Impact from diving bell drop weight· Impact from a ROV collision· Dropped control pod

The potential trajectory and resulting impact energy for this equipment if it is dropped has been assessed for most items using the DELTA software package (Ref. 8, 9 and 10). The simulations have been carried out assuming that items are dropped from a height of 25m above the sea surface at a range of orientations from horizontal to vertical in 10° increments. The current velocity of the water column has been assumed to be 0.66 m/s which corresponds to a return period in excess of 100 years. Results from the DELTA simulation work are shown in Table 1 and summarised below.


HorizontalDistance

Travelled (m)

ImpactEnergy

(kJ)DSV Clump Weight (small) 500 57 4.4DSV Clump Weight (large) 1,000 54 11.0Impact from Diving Bell Collision N/A N/A NegligibleDiving Bell Clump Weight 3,000 N/A 18.0Diving Bell Drop Weight 500 N/A 12.6Impact from ROV Collision N/A N/A NegligibleDropped Control Pod 1,000 52 12.0

These results indicate that all potential dropped objects under consideration for subsea intervention operations have impact energies within the criteria for Load Case C (Ref. 7).

Note that in the North Sea, diving bell clump weights (a circular ring located on the underside of the bell to provide a means of bringing the bell to the surface by jettisoning the clump weight) are generally welded up. The reason for this is that adequate rescue facilities are available to recover divers in a bell that has a severed lift line. Inadvertent release of the clump weight would be a serious risk to divers since this would result in rapid decompression unless the diving bell hatch were securely closed at the time of jettisoning. Therefore, the risk of damage from a dropped diving bell clump weight can be ignored since it is assumed that the clump weight cannot be inadvertently dropped.

Conclusions for dropped objects and impacts during intervention operations

All potential dropped object and impact hazards during intervention operations are within Load Case C (Ref. 7). Therefore no additional precautions are necessary.

3.3.9 Impact from Other Major Accidents

Other major accidents that could occur at the subsea locations could have consequential effects on the subsea facilities. These scenarios are as follows.

· Impact from a sinking supply boat following a collision or dropped object onto the supply boat.· Impact from a sinking drilling rig due to collision damage, extreme weather, mooring failure or

loss of buoyancy in the event of a subsea blowout.· Impact from a sinking helicopter following a collision during landing or take off from the drilling rig

or DSV.

All these accident scenarios could involve significant loss of life and assets in their own right and also cause damage to the subsea facilities.



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A supply boat could be sunk due to a collision with the drilling rig or as a result of an object being dropped onto the vessel during transfer operations which had sufficient energy to penetrate the hull. If such an event occurred and the supply boat sunk onto the subsea facilities, this would result in serious damage and probably hydrocarbon releases. It is estimated that the impact energy from such an incident would be in the order of 64MJ. It is obviously not feasible to protect the subsea facilities against such impact forces so the only way in which the event can be mitigated against is to prevent the incident occurring or avoid impact if a vessel should be holed.

A supply boat could collide with the drilling rig for a number of reasons, either failure of propulsion or thrusters, severe weather, or human error. The likelihood of propulsion failure could be minimised by ensuring that only serviceable, well maintained supply boats are used. Collisions due to extreme weather could be minimised by setting weather limits for supply boat transfer operations. The potential for human error could be minimised by ensuring that only experienced vessel crews are used, by briefing the crews and providing good communications between the supply boat and drilling rig. Many of these factors could be incorporated in a simple procedure for supply boats which would give the vessel crew clear instructions to minimise the likelihood of human error.

During transfer operations, items such as containers, tubulars and other goods could be dropped and may land either in the sea or on the supply boat. If an object is dropped onto the supply boat there is a risk that it will puncture the hull, thereby flooding the vessel. However, crane operations avoid lifting loads directly over the supply boat by swinging the load away from the vessel after the initial lift. If a vessel is holed then it is unlikely that it will sink immediately. Depending on the severity of the damage, it may be some time before the vessel actually sinks. During this time, the supply boat could be steered away from the subsea facilities to a safe location before the vessel is abandoned.

A drilling rig could possibly sink for a number of reasons, including ship impact, catastrophic structural failure, severe weather or loss of buoyancy in a blowout or flowline rupture. Such an event would undoubtedly result in a significant loss of life and severe damage to the subsea facilities if hit by the sinking rig. It is obviously not feasible to protect the subsea facilities against such impact forces so the only way in which the event can be mitigated against is to prevent the incident occurring.

The regime of marine regulations and certification for semi submersible drilling rigs cover structural integrity, impact resistance (and loss of buoyancy) and the adequacy of mooring systems. The design of the subsea facilities does not affect these hazards to any considerable degree. However, the risk and consequences of ship collisions can be minimised by appropriate procedural controls. These controls include weather limits for loading operations, surveillance and monitoring of passing shipping and emergency response procedures to be used in the event of an impending collision from a passing vessel. These issues should be addressed as part of the operating and emergency response procedures for the drilling rig.

The rig could possibly be sunk due to loss of buoyancy in the event of a blowout or rupture of a flowline or process pipework. Such an event is unlikely given the precautions that will be taken to minimise the risk of damage from dropped objects. However, the risk of blowout cannot be eliminated entirely so this scenario will have to be considered. This scenario has already been raised (Ref. 2 and SAR SS-010-002) and will be addressed during detail design.

Dropped object and impact analysis for a sinking helicopter has not been assessed in this study. If a helicopter crashed into the sea during take off or landing then it is possible that the helicopter could hit the subsea facilities. However, the stiffness of a helicopter is likely to be significantly less than that of the subsea facilities and a large proportion of the impact energy is likely to be absorbed by the helicopter.



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Conclusions for impact from other major accidents

Dropped object and impact hazards associated with other major accidents obviously cannot be protected against by physical means. For the 3 major accidents under consideration, procedural controls can help reduce the likelihood of occurrence but risks cannot be eliminated. Therefore, it is appropriate to consider emergency response plans that could be used to help mitigate against the consequences of these events.

The consequences of a supply boat sinking could be reduced by steering the boat away from the facilities prior to sinking so that the risk of the boat sinking onto the subsea facilities is minimised. Precautionary measures could also be taken by the rig (or DSV) to initiate a full subsea ESD to minimise the potential for hydrocarbon releases if a supply boat is in imminent danger of sinking. These actions should be incorporated into the emergency response procedures.

The consequences of a rig sinking could also be mitigated against in a similar way by attempting to move the rig away from the subsea facilities before it sinks and by initiating a full subsea ESD. Again, these actions should be incorporated into the emergency response procedures.

The consequences of impact from a sinking helicopter could be mitigated against by initiating a full subsea ESD which would minimise the potential for hydrocarbon releases if a helicopter crashes into the sea adjacent to the rig or DSV. This action should be incorporated into the emergency response procedures.

3.3.10 Impacts from Fishing Activity

A number of impact and snag load scenarios have been identified for the subsea facilities (Ref. 3 and 17). These scenarios are as follows.

· Impact from fishing gear (trawl boards and beam trawl)· Snag load from fishing gear· Pull over load from trawl boards on pipelines· Pull over load from trawl boards on subsea structures

The work carried out on impacts and snag loads from fishing gear in Ref. 3 and 17 determines the maximum anticipated forces associated with fishing activity. These loads have been used to define Load Cases A and B (Ref. 7). Since all subsea facilities will be designed to meet these Load Case criteria, adequate protection against fishing activity is provided.

Conclusions for impacts from fishing activity

Load Cases A and B (Ref. 7) provide adequate protection against all potential impact and snag load hazards associated with fishing operations.

3.4 Generalised Results from Dropped Object and Impact Analysis

In order to apply the results of the dropped object analysis contained in this study and allow simple emergency response guidelines to be prepared, it is appropriate to generalise the result due to impacts from dropped objects. The potential for releases due to the impact energy of dropped objects exceeding the rupture energy of the pipework is shown in Table 2 for unprotected pipework and in Table 3 for pipework which is protected by subsea structures, covers, mattresses or rock dump. Note that 14”, 8” and 5” pipework shown in Tables 2 and 3 normally contains produced hydrocarbons whilst the 3” pipework normally contains methanol. The 1” and 2” pipework can contain either methanol or annulus fluids but could result in hydrocarbon releases if ruptured when this pipework is not isolated from the wells or manifold headers. The smaller pipework sizes have been included in the analysis to provide a complete assessment of the subsea pipework and to provide information for the correlation shown in Figure 5.



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In order to provide practical emergency response guidelines on actions to be taken in the event of a dropped object, a simple approach is needed based on the information readily available to the crew on the vessel at the time of the incident. If a dropped object incident occurs, the deck crew will be able to relay what was dropped (and the approximate weight) and where it was dropped to the rig OIM or vessel master with a reasonable degree of confidence. The rig OIM or vessel master will know the position of the vessel relative to the subsea facilities and will have to make a decision to initiate a subsea shutdown on this information alone as fast as possible.

Ideally, the guidelines should lead to a subsea shutdown being initiated for all dropped objects that could cause a release. Where the dropped object has insufficient impact energy to cause a release or if the dropped object cannot reach the subsea facilities because it has been dropped over the heavy goods handling area, then a subsea shutdown should not be initiated.

In order to determine an appropriate threshold for the weight of an object which if dropped could cause a release from unprotected pipework on the subsea facilities, the results of the dropped object analysis have been further analysed. This has been carried out by plotting the weight of the dropped object versus the resulting impact energy for the potential dropped objects identified in Table 2, as shown in Figure 5. These results have been plotted by category depending on the potential of the dropped object to rupture different size unprotected pipework.

This approach allows the potential for hydrocarbon releases due to damage from dropped objects to be assessed based on the weight of the dropped object alone. This will allow simplified emergency response guidelines and allow the potential impact of dropped objects which have not been considered to date in the dropped object analysis to be reasonably estimated.

From Figure 5, it can be seen that the minimum weight of a dropped object scenario considered in Table 2 which could rupture a 5” flowline between a well and the manifold is 10 tonnes. Note that smaller diameter pipework (1”, 2” and 3”) does not generally contain produced hydrocarbons under pressure with the exception of the 1” annulus bleed line which is normally at test flowline pressure.

Note also that all pipework in the subsea facilities is protected against impact damage by either protective covers, rock dump or by the structural elements of the manifold or bundle trail head. This protection is ignored in the analysis of potential ruptures discussed above and therefore, it is conservative to assume that the minimum dropped object weight which could cause a hydrocarbon release is 10 tonnes.

Since the position of the heavy goods handling areas relative to the subsea facilities have been determined from the dropped object trajectory analysis (Ref. 6), it can be assumed that any object dropped within the heavy goods handling area assigned for the object is unlikely to impact the subsea facilities and therefore unlikely to cause a release. However, this analysis is based on mathematical predictions of dropped object trajectories through the water and hence should be treated with caution. Therefore, even if an object is dropped in the heavy goods handling area assigned for the object, emergency response actions should be still taken to ensure that the object has not hit the subsea facilities.

For dropped objects greater than 10 tonnes which are dropped onto the subsea facilities, the probability of a release will increase as the weight of the dropped object increases. Therefore, it is appropriate to take more positive emergency response actions on the basis that a release is more likely with heavier dropped objects.

Likewise, a dropped object greater that approximately 20 tonnes will threaten the 8” and possibly 14” pipework leading to more severe consequences from the potential release rate from the production and test headers and flowlines.

The potential gas dispersion and fire scenarios can thus be linked to the dropped objects weight and the point at which it is dropped relative to the subsea facilities. This information is used as the basis of the emergency response guidelines presented in Section 5.

3.5 Dropped Object Summary



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This section provides a summary of the potential dropped objects which exceed the Load Case criteria (Ref. 7) and must be protected against by carrying out the running, retrieval, loading or transfer operations at a suitable safe distance from the seabed facilities.

In order to rationalise the number of cases to be considered in the layout analysis and to simplify loading and transfer operations on drilling rigs and other vessels, 3 cases are proposed as follows.

1. When running or retrieving the BOP or subsea trees, a minimum horizontal separation distance of 28m should be maintained between the centre of the moonpool and the nearest subsea facilities.

2. When loading trees, heavy equipment (such as mud pumps and rig winches), 10" drill collars and other items of equipment (see Table 7), a minimum horizontal separation distance of 28m should be maintained between the loading area and the nearest subsea facilities.

3. When loading 36", 30" and 20” casing, coiled tubing reels, coiled tubing injector heads and other items of equipment (see Table 7), a minimum horizontal separation distance of 42m should be maintained between the loading area and the nearest subsea facilities.

The minimum safe handling distance for all identified dropped object scenarios which exceed the Load Case criteria (Ref. 7) are summarised in Table 7.



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4.0 SUBSEA LAYOUT

This section addresses the layout of the subsea facilities where the primary objective is to develop a layout which meets the design objectives described in Section 4.2, below. The layout is developed in part from the results of the dropped object analysis which identifies dropped object and impact hazards that exceed the Load Case criteria (Ref. 7) which must be protected against by procedures. Where possible, protection against these dropped object hazards (see Section 3.4) is provided by sufficient horizontal separation between the point from which objects can be dropped and the subsea facilities.

4.1 Rig Considerations

A total of 26 semi submersible drilling rigs have been identified for potential use on the Britannia development for drilling of subsea and template wells. These drilling rigs are as follows.

1. Diamond Offshore Ocean Alliance2. Ocean Guardian3. Ocean Valiant4. Global Marine Glomar Arctic 15. Glomar Arctic 36. Lauritzen Offshore Dan Princess7. Maersk Drilling Maersk Vinlander8. Neddrill Neddrill 69. Ross Offshore Vildkat Explorer10. Saipem Scarabeo 511. Santa Fe Santa Fe Rig 13512. Santa Fe Rig 14013. Sedco Forex Sovereign Explorer14. Drillstar15. Sedco 71116. Sedco 71217. Sedco 71418. Smedvig West Alpha19. West Delta20. West Vanguard21. Sonat Sonat Arcade Frontier22. Sonat Rather23. John Shaw24. Stena Dyvi Stena25. Transocean Transocean 826. Western Oceanic Western Pacesetter IV

A thorough assessment of the design features that could affect the subsea layout for these rigs has been made (Ref. 11) which addressed the following topics.

1. Proposed mooring pattern2. Mooring system catenary touch down points3. Preferred rig heading4. Overall dimensions of main deck5. Rig side for loading of trees6. Rig side for loading of tubulars

The findings from this assessment for these 6 topics are summarised in Sections 4.1.1 to 4.1.6.



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4.1.1 Proposed Mooring Pattern

An 8 point mooring system is used on all rigs under consideration except the Neddrill 6 and the West Delta which have a 12 point mooring systems. The most common mooring system has anchors spaced at regular 45° intervals which is used by 19 of the 26 rigs under consideration. Five rigs use an irregular anchor spacing of 30° between the two anchors at each corner of the rig and 60° between the nearest anchors on adjacent corners.

Interpretation of the mooring analyses that have been carried out for rigs with alternative anchor locations indicate that the increase in line tensions experienced with a non symmetrical anchor pattern (i.e., anchors not spaced at regular 45° intervals) are not significant and allow safety margins in the storm survival condition to be maintained. The conclusion is therefore that anchors can be positioned to avoid existing seabed obstructions such as exploration wells without adversely compromising mooring performance. On this basis, it can be assumed that anchors can be positioned with a tolerance of ± 5° from the nominal position.

4.1.2 Catenary Touch Down Points

Catenary touch down zones vary with the type of mooring system used on the rigs and anchor tensions applied during rough weather. During normal operations, the intention is to keep the rig precisely located over the subsea facilities which is achieved by increasing anchor tensions. During rough weather (storm survival conditions), the intention is to ride out the storm without exposing the anchors to excessive tensions by slackening off the mooring system. When anchor tensions are reduced, more anchor chain is placed on the seabed which is lifted to absorb rig motions due to wind and wave action. This gives the worst case condition that results in the touch down zones closest to the rig.

From the responses obtained, only those from Diamond and Saipem give full dynamic analyses in sufficient detail to establish a realistic touch down radius under storm survival conditions. These results indicate that under storm survival conditions the minimum touch down distance occurs on the leeward anchors which can touch the seabed as close as 15m horizontally from the fairleader.

From the responses obtained for normal operating conditions the touch down points ranged from 76m to 578m. Following clarification of this point with vessel owners (Ref. 13 to 16) it is assumed there is no problem in maintaining a 250m touch down radius under normal operating conditions for all rigs under consideration.

4.1.3 Preferred Rig Heading

Many of the rig owners responded with a preferred heading of 330°. However, in some instances, rig owners gave a range of possible headings that would be acceptable which varied from 220° (approximately South West) to 7° (approximately North).

Further correspondence with rig owners (Ref. 13 to 16) indicates that a rig heading of 6° is acceptable which is suitable for the infield pipeline orientation of the Britannia field.

4.1.4 Overall Dimensions of Main Deck

The overall dimensions of the rig main deck are necessary to determine the envelope of the rig with respect to anchor chain touch down zones and dropped object impact zones. The dimensions of the 'average' rig is approximately 73.7m long by 62.6 wide. Of the rigs under consideration, the maximum and minimum length of the main deck is 91.9m and 61.0m respectively and the maximum and minimum width of the main deck is 76.5m and 53.6m respectively.



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4.1.5 Rig Side for Loading of Trees

Of the 26 rigs under consideration, 10 load trees from the left side, 10 from the right, 2 from either left or right and 2 from the rear, together with 2 unknown. The conclusion is therefore that the rigs under consideration do not have a left or right handed bias and therefore the layout should allow loading of trees from either side of the rig.

4.1.6 Rig Side for Loading of Tubulars

Of the 26 rigs under consideration, most can load tubulars from either side of the rig. However, the information supplied by some rig owners does not differentiate between tubular storage areas designed for drill string, tubing, casing or riser sections. The conclusion is therefore that the rigs under consideration do not have a left or right handed bias and therefore the layout should allow loading of tubulars from either side of the rig.

4.2 Typical Rig Geometries

In order to develop the seabed layouts, the hazardous dropped object areas where impact forces could exceed the Load Case criteria (Ref. 7) have been developed for a generic drilling rig based on the average rig dimensions given in Section 4.1.4. This generic rig is shown in Figure 6. Note that anchors have been numbered for discussion purposes only.

The dropped object trajectory results given in Section 3.4 have been used to determine the drop out zones for dropped objects which indicate the maximum extent of where the dropped objects may impact the seabed. These drop out zones are shown relative to the generic rig in Figures 10 to 12. Note that the drop out zones for rig loading activities are shown for the left side crane only. In practice either the left or right side cranes may be used for these loading operations as discussed in Sections 4.1.5 and 4.1.6.

Some general conclusions can be drawn from the drop out zones shown in Figures 10 to 12, as follows.

· When loading trees, heavy equipment and 10" drill collars, the drop out zone does not encroach over the centre of the rig which will allow the rig to remain on a well during the loading operations without risk of damage if the equipment is dropped, provided the drop out zone does not encroach over other seabed facilities. Simultaneous BOP running and retrieval operations and loading of trees, heavy equipment and 10" drill collars will also be permissible because these objects could not hit the BOP if dropped.

· When loading 36", 30" and 20" casing, the drop out zones encroach over the centre of the rig and therefore the rig cannot load these tubulars whilst drilling a well without risk of damage if the equipment is dropped. This implies that these tubulars will have to be loaded during rig moves between wells. However, it may be possible to carry out loading operations whilst batch setting the initial wells because the only facilities installed at this point in time are the subsea wellheads which may be capable of resisting the impact energies for these dropped objects, as given in Section 3.3.3.

· When loading coiled tubing equipment, the potential drop out zone encroaches well over the centre of the rig and therefore it will not be possible to load this equipment whilst remaining on a well without risk of damage if the equipment is dropped.

4.3 Seabed Layout Design Objectives

The design goals and objectives for the seabed layout have been developed to satisfy general requirements that cover operational and safety issues and also hazards that are covered by procedural control (see Section 3.4). These design objectives are as follows.

· Allow rig loading away from seabed facilities when drilling· Allow moving with suspended BOP away from wells· Allow rig loading away from seabed facilities when running BOP· No anchor touch down zones across pipelines



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· Minimise length of flowline spools· Minimise length of well jumper spools· Provide adequate thermal expansion· Allow a rig that gives acceptable mooring design and minimises weather downtime· Pipelines are well away from dropped object zones· Avoid requirement for excessive additional protection· Adequate clearance for pipeline laying· Clear routes for satellite well flowlines· ROV access to all sides of manifold when drilling· Adequate space for installation of temporary pig launching facilities· Provide 28m horizontal clearance for BOP running and retrieval operations· Provide 28m horizontal clearance for tree running and retrieval operations· Provide 25m horizontal clearance for tree loading operations· Provide 39m horizontal clearance for 36" and 30" casing loading operations· Provide 28m horizontal clearance for 10" drill collar loading operations· Provide 25m horizontal clearance for heavy equipment (winches, mud pumps, etc.) loading

operations· Provide 47m horizontal clearance for coiled tubing reel loading operations· Provide 55m horizontal clearance for coiled tubing injector head loading operations

Ideally, the seabed layout of the subsea centre should satisfy all these design objectives. However, it may not be possible to satisfy all objectives in which case additional procedures may be necessary. In developing the optimum configuration, consideration will be given to general safety issues, costs associated with drilling, intervention and maintenance and the general operability of the facilities.

4.4 Layout of Subsea Facilities

A unique feature of the Britannia development is the use of heated flowlines, either using bundles or a coaxial pipe in pipe system. Since the heating system is critical to production, protection of the flowlines is a critical issue which has been given a high priority.

The seabed layout presented in this report has wells arranged it two groups. The first 8 wells to be drilled are arranged in a 2 by 4 matrix with the wells spaced at 15m centres. These wells will be pre-drilled before any other subsea facilities are installed. An additional 6 well locations are also provided in a 2 by 3 matrix with the wells spaced at 15m centres. This layout is shown in Figure 9. Note that wells are numbered for discussion purposes only and do not represent actual well numbering.

The sketches showing the dropped object hazardous areas associated with the rig have been overlaid on the seabed layout to determine if there is sufficient clearance between the seabed facilities and the drop out zones. For the initial pre-drilling operations, make up of riserless drill strings and BOP running and retrieval operations can be carried out simply by moving away from the wells. When future wells are drilled and for workover operations, BOP running and retrieval operations can be carried out by moving off the well to safe locations outside the 28m boundary, as shown in Figure 9.

Loading of trees, heavy equipment and 10" drill collars cannot be carried out in general whilst drilling wells since the drop out zone encroaches over the manifold or other wells. The only exceptions are left handed loading operations when only the first 8 wells are installed whilst working on well 7. For right handed loading operations, trees, heavy equipment and 10" drill collars can be loaded whilst working on wells 6 and 8. Restrictions will have to be applied for all other wells when loading these goods where the rig is moved off the well to a safe location during the loading operations. Note that rigs that load trees from the rear would have to move a considerable distance from the wells.



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Under storm survival conditions, the rig will have to move off the well that is being worked on to a safe location where the anchor chains straddle the pipelines. This is necessary to ensure that the anchor chain touch down points (which may be as close as 15m to the rig) do not impact the subsea facilities. This rig position is shown in Figure 13.

A potential problem with this layout is anchor chain interference with the pipelines on anchor No 3. When working on well 8 or during BOP running and retrieval operations, the distance between the rig fairleader and the point where the anchor chain crosses the pipelines is approximately 260m. In order to prevent anchor chain No 3 impacting the pipelines, sufficient anchor tension will have to be maintained to ensure that the touch down point is further than 260m from the rig. It is assumed that this will be possible from the responses received from rig owners (Ref. 13 to 16). However, the behaviour of mooring systems is rig specific and no further work on this subject is possible until the rig is selected. If there is a problem with anchor chain impacts a number of solutions are possible. These include moving anchor No 3 or changing the rig heading to reduce the distance between the rig fairleader and the point where the anchor chain crosses the pipelines. Alternatively, the anchor chain could be buoyed to prevent touch down or a section of wire could be inserted to extend the catenary. These solutions will only be considered following mooring analysis for the selected rig.



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5.0 REFERENCES

1. Project Safety Plan, BRT0-XO0-NO-O0-00-01003, Rev B2.2. Subsea Hazard Identification and Screening Report, BRT0-XS0-XR-S0-55-00010, Rev B1.3. Trawlgear and Dropped Object Accidental Loads on Coaxial and Bundled Flowlines, BRT0-XS0-

QR-S0-55-10002, Rev B1.4. Conoco (U.K.) Ltd, Hazard Protection Study Subsea Installations, Cameron Atkins Technology,

Final Report, August 1988.5. Dropped Objects on Subsea Installations, SINTEF, STF75 A89039, ISBN 82-595-5768-1.6. An Initial Appraisal of the Threat of Damage to Subsea Installations, UEG Technical Note 27,

November 1982.7. Subsea Facilities Basis of Design, BRT2-XS0-XB-S0-55-00001, Rev B1.8. DELTA User Guide, Noble Denton, January 1992.9. Motion Simulation and Hazard Assessment of Dropped Objects, Y Luo and J Davies, Noble

Denton.10. Reliability Analysis of the Behaviour of Dropped Objects, R Colwill and R Ahilan, Noble Denton,

OTC 1992.11. Rig Considerations for Subsea Layout, Britannia Subsea Technical Note 013.12. Murchinson Platform loading operations, April 1994, Conoco Materials and Logistics, Dept,

Aberdeen. Fax communication, 2/8/94.13. Internal memo, Saipem Scarabeo 5, Cesare Calef, 418/94-70.BRI, 8 March 1994.14 Letter, Neddrill, Cees Van Diemen, CVD/wm.007, 24 February 1994.15. Letter, Western Oceanic, Peter Ramsey, PR/0458/94, 7 March 1994.16. Letter, Stena Offshore, John Davies, LTR/SDR/JDA/440, 4 March 1994.17. Tree Protection and Elevation Philosophy, BRT3-XS0-QR-S1-56-00001, Rev D1.18. Dropped Object Study for Pre-Drilling Activities at Platform Template, BRT2-XS0-NR-S0-55-

00033, Rev D1.19. Manifold Structural Design Calculations, BRT2-XS0-QC-S2-56-00007.20. Manifold Trailhead Protection Cover Structural Design Calculations, BRT2-XS0-QC-S3-56-

00005.



Rev D2

Appendix 1

Tables and Figures

Table 1 Dropped Objects and Impact ScenariosTable 2 Potential for Rupture of Unprotected Subsea Pipework from Dropped Objects and Impact

ScenariosTable 3 Potential for Rupture of Protected Subsea Pipework from Dropped Objects and Impact

ScenariosTable 4 Summary Calculations for Tubular Dropped Object and Impact AnalysisTable 5 Summary Calculations for Container Dropped Object and Impact AnalysisTable 6 Summary Calculations for Wireline & Coiled Tubing Dropped Object and Impact AnalysisTable 7 Dropped Objects and Impacts to be Protected Against by Procedural ControlsFigure 1 Probability of Impact for Dropped BOPFigure 2 Probability of Impact for Dropped TreeFigure 3 Behaviour of 9.625” Casing when Dropped at Near Vertical Angles through Still WaterFigure 4 Impact Probability versus Distance from Drop Point for Floating ContainersFigure 5 Correlation of Dropped Object Weight in Air versus Impact EnergyFigure 6 Schematic Layout of Generic Drilling RigFigure 7 Schematic Layout of Sedco Sovereign Explorer Drilling Rig used for Pre-Drilling

OperationsFigure 8 Schematic Layout of Sedco Drillstar Drilling Rig used for Initial Well Completion

OperationsFigure 9 Subsea Centre Seabed LayoutFigure 10 Typical 28m Dropped Object Drop Out Zone from Moonpool on Generic Drilling RigFigure 11 Typical 28m Dropped Object Drop Out Zones from Port and Starboard Cranes on

Generic Drilling RigFigure 12 Typical 42m Dropped Object Drop Out Zones from Port and Starboard Cranes on

Generic Drilling RigFigure 13 Typical Severe Weather Stand Off Positions for Sedco DrillstarFigure 14 Typical Hydrocarbon Release Emergency Stand Off Positions for Sedco Drillstar



Rev D2

Dropped Object or Impact ScenarioWeightin Air(kg)

TotalMass

(kg) [1]

Distance Travelled

(m)

Impact Velocity

(m/s)

TotalImpactEnergy

(kJ)

EffectiveImpactEnergy

(kJ)

Source (see

report)

Blowout Preventor (BOP) 140,600 176,500 11 10.5 9,730 9,730 [2]

Subsea Tree (inc completion riser assembly) 140,600 176,500 11 10.5 9,730 9,730 [2]

Subsea Tree 35,000 50,000 20 7.0 1,225 1,225 [2]

36" Casing Single 10,051 25,154 33 3.3 133 133 [3]

30" Casing Single 5,633 16,296 33 3.3 87.6 87.6 [3]

20" Casing Single 2,352 7,111 44 2.6 24.4 24.4 [3]

13.375" Casing Single 1,207 3,315 52 2.3 9.0 9.0 [3]

13.375" Casing Bundle x 3 3,620 11,400 41 2.8 43.4 28.9 [3]

10.75" Casing Single 900 2,246 54 2.3 5.7 5.7 [3]

10.75" Casing Bundle x 4 3,601 11,919 44 2.6 40.5 20.3 [3]

9.625" Casing Single 840 1,904 53 2.3 5.0 5.0 [3]

9.625" Casing Bundle x 4 3,360 9,966 43 2.7 36.0 18.0 [3]

7" Liner Single 522 1,075 59 2.1 2.4 2.4 [3]

7" Liner Bundle x 7 3,657 8,144 36 3.2 40.4 17.3 [3]

5.5" Tubing Single 307 650 70 1.9 1.1 1.1 [3]

5.5" Tubing Bundle x 7 2,148 4,932 43 2.7 18.4 18.4 [3]

5.5" Tubing [8] Length x 3 920 1,950 107 2.8 7.6 7.6 [3]

4.5" Tubing Single 223 450 75 1.8 0.7 0.7 [3]

4.5" Tubing Bundle x 7 1,558 3,407 46 2.6 11.3 4.8 [3]

4.5" Tubing [8] Length x 3 668 1,350 110 2.7 4.9 4.9 [3]

6.625" Drill Pipe Single 461 832 52 2.3 2.2 2.2 [3]

6.625" Drill Pipe [8] Length x 4 1,844 3,327 93 3.5 20.1 20.1 [3]

5.5" Drill Pipe Single 339 540 53 2.3 1.4 1.4 [3]

5.5" Drill Pipe [8] Length x 4 1,355 2,160 95 3.5 13.1 13.1 [3]

5" Drill Pipe Single 376 624 52 2.3 1.7 1.7 [3]

5" Drill Pipe [8] Length x 4 1,505 2,497 94 3.5 15.2 15.2 [3]

10" Drill Collar Single 3,479 4,006 22 5.0 49.2 49.2 [3]

10" Drill Collar [8] Length x 4 13,914 16,026 50 6.1 299 299 [3]

8" Drill Collar Single 2,218 2,557 25 4.4 25.2 25.2 [3]

8" Drill Collar [8] Length x 4 8,872 10,227 60 6.0 183 183 [3]

6.5" Drill Collar Single 1,101 1,254 29 3.8 9.0 9.0 [3]

6.5" Drill Collar [8] Length x 4 4,403 5,016 70 5.6 78.4 78.4 [3]

Drilling Riser Single 2,503 9,158 51 2.4 25.7 25.7 [3]

Drilling Riser [9] Length x 2 5,006 18,316 68 2.4 51.4 51.4 [3]

Completion Riser Single 1,001 1,782 50 2.6 5.8 5.8 [3]

Completion Riser [9] Length x 2 2,002 3,565 77 3.3 19.1 19.1 [3]

Container Mini Empty [10] [12] Horizontal 1,620 19,473 60 2.0 37.6 37.6 [3]

Container Mini Full [10] [12] Horizontal 6,000 23,282 30 3.6 153 153 [3]

Container Mini Full [11] Vertical 6,000 22,623 42 4.4 222 222 [3]

Table 1Dropped Objects and Impact Scenarios



Rev D2


TotalMass

(kg) [1]

Distance Travelled

(m)

Impact Velocity

(m/s)

TotalImpactEnergy

(kJ)

EffectiveImpactEnergy

(kJ)

Source (see

report)

Container 10' Empty [10] [12] Horizontal 2,000 28,261 66 1.9 49.9 49.9 [3]

Container 10' Full [10] [12] Horizontal 8,000 33,478 31 3.6 214 214 [3]

Container 10' Full [11] Vertical 8,000 31,964 44 4.6 344 344 [3]

Container 20' Empty [10] [13] Horizontal 3,000 111,402 117 1.9 211 211 [3]

Container 20' Full [10] [13] Horizontal 18,000 124,446 39 3.2 635 635 [3]

Container 20' Full [11] Vertical 18,000 113,739 11 4.9 1,384 1,384 [3]

Rig Winch 25,000 25,000 20 6.0 450 450 [4]

Drilling Mud Pump 33,000 33,000 20 7.0 810 810 [4]

Sledge Hammer 5 7 8 24.6 2.1 2.1 [4]

Failure of ancillary structure on rig or vessel 500 500 20 5.0 6.3 6.3 [7]

W/L Control & Reel Container [10] [12] Horizontal 5,000 55,638 64 1.8 90.6 90.6 [3]

W/L Control & Reel Container [11] Vertical 5,000 53,075 48 2.1 113 113 [3]

W/L BOP 1,000 1,297 22 4.6 13.8 13.8 [3]

W/L Lubricator Joints 900 2,246 54 2.3 5.7 5.7 [6]

C/T Control Container [10] [12] Horizontal 5,500 57,046 61 1.9 101 101 [3]

C/T Control Container [11] Vertical 5,500 53,941 45 2.3 142 142 [3]

C/T PSU Container [10] [12] Horizontal 6,954 64,043 56 2.0 132 132 [3]

C/T PSU Container [11] Vertical 6,954 58,074 40 2.5 185 185 [3]

C/T Tubing Reel 11,500 113,554 44 2.7 407 407 [3]

C/T Injector Head 5,400 78,825 52 2.0 157 157 [3]

Dropped Anchor during Running or Retrieval 7,900 10,000 24 4.3 90.0 90.0 [5]

Impact from a broken anchor chain 50 kg/link N/A N/A N/A 2.0 2.0 [7]

Impact from anchor chain at catenary touch down N/A N/A N/A N/A 5.0 5.0 [7]

Snag load from dragged anchor N/A N/A N/A N/A 3,750 kN 3,750 kN [2]

DSV Clump Weight Large 1,000 1,403 54 4.0 11.0 11.0 [3]

DSV Clump Weight Small 500 702 57 3.6 4.4 4.4 [3]

Impact from a diving bell collision N/A N/A N/A 0.1 Negligible Negligible [7]

Impact from diving bell clump weight 3,000 4,000 N/A 3.0 18.0 18.0 [7]

Impact from diving bell drop weight 500 702 N/A 6.0 12.6 12.6 [7]

Impact from a ROV collision N/A N/A N/A 0.1 Negligible Negligible [7]

Control Pod 1,000 3,250 52 2.8 12.0 12.0 [4]

Subsea wireline BOP 1,000 1,297 22 5 14 13.8 [3]

Subsea wireline lubricator 900 2,246 54 2 6 5.7 [6]

Impact from a vessel sinking 5,000 T 20,000 T N/A 8.0 64,000 64,000 [7]

Impact from fishing gear N/A N/A N/A N/A 45.0 45.0 [5]

Snag load from fishing gear N/A N/A N/A N/A 500 kN 500 kN [2]

Pull over load from fishing gear N/A N/A N/A N/A 230 kN 230 kN [5]

Table 1 (continued)Dropped Objects and Impact Scenarios



Rev D2

Impact On Unprotected 14" dia x

20.0mm wt


15.2mm wt


15.9mm wt


8.7mm wt


6.3mm wt


4.5mm wt


EffectiveImpact

Energy (kJ)

RuptureEnergy

(kJ)

Effect Rupture Energy

(kJ)


(kJ)


(kJ)


(kJ)


(kJ)

Effect Worst Case Release Scenario

Blowout Preventor (BOP) 140,600 9,730 2,194 FB Rupture 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 10Subsea Tree (inc. completion riser) 140,600 9,730 2,194 FB Rupture 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 10Subsea Tree 25,000 1,225 2,194 30mm Hole 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 336" Casing Single 10,051 133 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 230" Casing Single 5,633 87.6 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 220" Casing Single 2,352 24.4 2,194 Intact 666 Intact 372 Intact 67 Intact 22 FB Rupture 5 FB Rupture Case 213.375" Casing Single 1,207 9.0 2,098 Intact 666 Intact 372 Intact 67 Intact 22 10mm Hole 5 FB Rupture Case 213.375" Casing Bundle x 3 3,620 28.9 2,098 Intact 666 Intact 372 Intact 67 10mm Hole 22 FB Rupture 5 FB Rupture Case 210.75" Casing Single 900 5.7 1,685 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 FB Rupture Case 210.75" Casing Bundle x 4 3,601 20.3 1,685 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 29.625" Casing Single 840 5.0 1,506 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 FB Rupture Case 29.625" Casing Bundle x 4 3,360 18.0 1,506 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 27" Liner Single 522 2.4 1,097 Intact 540 Intact 372 Intact 67 Intact 22 Intact 5 10mm Hole Case 17" Liner Bundle x 7 3,657 17.3 1,097 Intact 540 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 25.5" Tubing Single 307 1.1 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Tubing Bundle x 7 2,148 18.4 862 Intact 424 Intact 368 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 25.5" Tubing Length x 3 920 7.6 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 FB Rupture Case 24.5" Tubing Single 223 0.7 705 Intact 347 Intact 301 Intact 67 Intact 22 Intact 5 Intact No Release4.5" Tubing Bundle x 7 1,558 4.8 705 Intact 347 Intact 301 Intact 67 Intact 22 Intact 5 FB Rupture Case 24.5" Tubing Length x 3 668 4.9 705 Intact 347 Intact 301 Intact 67 Intact 22 Intact 5 FB Rupture Case 26.625" Drill Pipe Single 461 2.2 1,038 Intact 511 Intact 372 Intact 67 Intact 22 Intact 5 10mm Hole Case 16.625" Drill Pipe Length x 4 1,844 20.1 1,038 Intact 511 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 25.5" Drill Pipe Single 339 1.4 784 Intact 386 Intact 334 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Drill Pipe Length x 4 1,355 13.1 784 Intact 386 Intact 334 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 25" Drill Pipe Single 376 1.7 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release5" Drill Pipe Length x 4 1,505 15.2 862 Intact 424 Intact 368 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 210" Drill Collar Single 3,479 49.2 1,567 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture Case 210" Drill Collar Length x 4 13,914 299 1,567 Intact 666 10mm Hole 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 28" Drill Collar Single 2,218 25.2 1,254 Intact 617 Intact 372 Intact 67 Intact 22 FB Rupture 5 FB Rupture Case 28" Drill Collar Length x 4 8,872 183 1,254 Intact 617 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 26.5" Drill Collar Single 1,101 9.0 862 Intact 424 Intact 368 Intact 67 Intact 22 10mm Hole 5 FB Rupture Case 26.5" Drill Collar Length x 4 4,403 78.4 862 Intact 424 Intact 368 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Drilling Riser Single 2,503 25.7 2,194 Intact 666 Intact 372 Intact 67 Intact 22 FB Rupture 5 FB Rupture Case 2Drilling Riser Length x 2 5,006 51.4 2,194 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture Case 2Completion Riser Single 1,001 5.8 1,254 Intact 617 Intact 372 Intact 67 Intact 22 Intact 5 FB Rupture Case 2Completion Riser Length x 2 2,002 19.1 1,254 Intact 617 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2Container Mini Empty Horizontal 1,620 37.6 2,194 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture Case 2Container Mini Full Horizontal 6,000 153 2,194 Intact 666 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container Mini Full Vertical 6,000 222 2,194 Intact 666 Intact 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2

Table 2Potential for Rupture of Unprotected Subsea Pipework from Dropped Objects and Impact Scenarios



Rev D2


20.0mm wt


15.2mm wt


15.9mm wt


8.7mm wt


6.3mm wt


4.5mm wt


EffectiveImpact

Energy (kJ)

RuptureEnergy

(kJ)


(kJ)


(kJ)


(kJ)


(kJ)


(kJ)


Container 10' Empty Horizontal 2,000 49.9 2,194 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture Case 2Container 10' Full Horizontal 8,000 214 2,194 Intact 666 Intact 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container 10' Full Vertical 8,000 344 2,194 Intact 666 10mm Hole 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container 20' Empty Horizontal 3,000 211 2,194 Intact 666 Intact 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container 20' Full Horizontal 18,000 635 2,194 Intact 666 30mm Hole 372 100mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3Container 20' Full Vertical 18,000 1,384 2,194 30mm Hole 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 6Rig Winch 25,000 450 2,194 Intact 666 30mm Hole 372 100mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3Drilling Mud Pump 33,000 810 2,194 Intact 666 100mm Hole 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3Sledge Hammer 5 2.0 31 Intact 15 Intact 13 Intact 4 Intact 2 Intact 1 Intact No ReleaseFailure of ancillary structure on rig/vessel 500 12.0 1,543 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2W/L Control & Reel Container Horizontal 5,000 90.6 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2W/L Control & Reel Container Vertical 5,000 114 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2W/L BOP 1,000 13.8 987 Intact 486 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2W/L Lubricator Joints 900 5.7 100 Intact 49 Intact 42 Intact 12 Intact 6 Intact 2 FB Rupture Case 2C/T Control Container Horizontal 5,500 101 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2C/T Control Container Vertical 5,500 142 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2C/T PSU Container Horizontal 6,954 132 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2C/T PSU Container Vertical 6,954 204 2,194 Intact 666 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2C/T Tubing Reel 11,500 407 2,194 Intact 666 30mm Hole 372 100mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3C/T Injector Head 5,400 157 2,194 Intact 666 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Dropped Anchor during running/retrieval 7,900 90.0 1,234 Intact 608 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Impact from a broken anchor chain 50 kg/link 2.0 617 Intact 304 Intact 263 Intact 67 Intact 22 Intact 5 Intact No ReleaseImpact from anchor chain at touch down N/A 5.0 617 Intact 304 Intact 263 Intact 67 Intact 22 Intact 5 FB Rupture Case 2Snag load from dragged anchor N/A 3,750 kN N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Case 10DSV Clump Weight Large 1,000 11.0 2,194 Intact 666 Intact 372 Intact 67 Intact 22 10mm Hole 5 FB Rupture Case 2DSV Clump Weight Small 500 4.4 617 Intact 304 Intact 263 Intact 67 Intact 22 Intact 5 FB Rupture Case 2Impact from a diving bell collision N/A Negligible N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact No ReleaseImpact from diving bell clump weight 3,000 18.0 2,194 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2Impact from diving bell drop weight 500 12.6 926 Intact 456 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2Impact from a ROV collision N/A Negligible N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact No ReleaseControl Pod 1,000 12.0 2,194 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2Subsea wireline BOP 1,000 13.8 2,194 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture Case 2Subsea wireline lubricator 900 5.7 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 FB Rupture Case 2Impact from a vessel sinking 5,000 T 64,000 N/A FB Rupture N/A FB Rupture N/A FB Rupture N/A FB Rupture N/A FB Rupture N/A FB Rupture Case 10Impact from fishing gear N/A 45.0 1,234 N/A 608 N/A 372 N/A 67 N/A 22 N/A 5 N/A No ReleaseSnag load from fishing gear N/A 500 kN N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A No ReleasePull over load from fishing gear N/A 230 kN N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A No Release

Table 2 (continued)Potential for Rupture of Unprotected Subsea Pipework from Dropped Objects and Impact Scenarios



Rev D2

Impact On Protected 14" dia x 20.0mm wt







EffectiveImpact

Energy (kJ)

RuptureEnergy

(kJ)


(kJ)


(kJ)


(kJ)


(kJ)


(kJ)


Blowout Preventor (BOP) 140,600 9,730 2,194 FB Rupture 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 10Subsea Tree (inc. completion riser) 140,600 9,730 2,194 FB Rupture 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 10Subsea Tree 25,000 1,225 2,194 30mm Hole 666 100mm Hole 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 336" Casing Single 10,051 133 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 230" Casing Single 5,633 87.6 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 220" Casing Single 2,352 24.4 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release13.375" Casing Single 1,207 9.0 2,098 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release13.375" Casing Bundle x 3 3,620 28.9 2,098 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release10.75" Casing Single 900 5.7 1,685 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release10.75" Casing Bundle x 4 3,601 20.3 1,685 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release9.625" Casing Single 840 5.0 1,506 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release9.625" Casing Bundle x 4 3,360 18.0 1,506 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release7" Liner Single 522 2.4 1,097 Intact 540 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release7" Liner Bundle x 7 3,657 17.3 1,097 Intact 540 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Tubing Single 307 1.1 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Tubing Bundle x 7 2,148 18.4 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Tubing Length x 3 920 7.6 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release4.5" Tubing Single 223 0.7 705 Intact 347 Intact 301 Intact 67 Intact 22 Intact 5 Intact No Release4.5" Tubing Bundle x 7 1,558 4.8 705 Intact 347 Intact 301 Intact 67 Intact 22 Intact 5 Intact No Release4.5" Tubing Length x 3 668 4.9 705 Intact 347 Intact 301 Intact 67 Intact 22 Intact 5 Intact No Release6.625" Drill Pipe Single 461 2.2 1,038 Intact 511 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release6.625" Drill Pipe Length x 4 1,844 20.1 1,038 Intact 511 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Drill Pipe Single 339 1.4 784 Intact 386 Intact 334 Intact 67 Intact 22 Intact 5 Intact No Release5.5" Drill Pipe Length x 4 1,355 13.1 784 Intact 386 Intact 334 Intact 67 Intact 22 Intact 5 Intact No Release5" Drill Pipe Single 376 1.7 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release5" Drill Pipe Length x 4 1,505 15.2 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release10" Drill Collar Single 3,479 49.2 1,567 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture Case 210" Drill Collar Length x 4 13,914 299 1,567 Intact 666 10mm Hole 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 28" Drill Collar Single 2,218 25.2 1,254 Intact 617 Intact 372 Intact 67 Intact 22 Intact 5 Intact No Release8" Drill Collar Length x 4 8,872 183 1,254 Intact 617 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 26.5" Drill Collar Single 1,101 9.0 862 Intact 424 Intact 368 Intact 67 Intact 22 Intact 5 Intact No Release6.5" Drill Collar Length x 4 4,403 78.4 862 Intact 424 Intact 368 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Drilling Riser Single 2,503 25.7 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseDrilling Riser Length x 2 5,006 51.4 2,194 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture Case 2Completion Riser Single 1,001 5.8 1,254 Intact 617 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseCompletion Riser Length x 2 2,002 19.1 1,254 Intact 617 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseContainer Mini Empty Horizontal 1,620 37.6 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseContainer Mini Full Horizontal 6,000 153 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseContainer Mini Full Vertical 6,000 222 2,194 Intact 666 Intact 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2

Table 3Potential for Rupture of Protected Subsea Pipework from Dropped Objects and Impact Scenarios



Rev D2








EffectiveImpact

Energy (kJ)

RuptureEnergy

(kJ)


(kJ)


(kJ)


(kJ)


(kJ)


(kJ)


Container 10' Empty Horizontal 2,000 49.9 2,194 Intact 666 Intact 372 Intact 67 30mm Hole 22 FB Rupture 5 FB Rupture No ReleaseContainer 10' Full Horizontal 8,000 214 2,194 Intact 666 Intact 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container 10' Full Vertical 8,000 344 2,194 Intact 666 10mm Hole 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container 20' Empty Horizontal 3,000 211 2,194 Intact 666 Intact 372 30mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Container 20' Full Horizontal 18,000 635 2,194 Intact 666 30mm Hole 372 100mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3Container 20' Full Vertical 18,000 1,384 2,194 30mm Hole 666 FB Rupture 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 6Rig Winch 25,000 450 2,194 Intact 666 30mm Hole 372 100mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3Drilling Mud Pump 33,000 810 2,194 Intact 666 100mm Hole 372 FB Rupture 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3Sledge Hammer 5 2.0 31 Intact 15 Intact 13 Intact 4 Intact 2 Intact 1 Intact No ReleaseFailure of ancillary structure on rig/vessel 500 12.0 1,543 Intact 666 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture No ReleaseW/L Control & Reel Container Horizontal 5,000 90.6 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2W/L Control & Reel Container Vertical 5,000 114 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2W/L BOP 1,000 13.8 987 Intact 486 Intact 372 Intact 67 Intact 22 30mm Hole 5 FB Rupture No ReleaseW/L Lubricator Joints 900 5.7 100 Intact 49 Intact 42 Intact 12 Intact 6 Intact 2 FB Rupture No ReleaseC/T Control Container Horizontal 5,500 101 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture No ReleaseC/T Control Container Vertical 5,500 142 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture No ReleaseC/T PSU Container Horizontal 6,954 132 2,194 Intact 666 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture No ReleaseC/T PSU Container Vertical 6,954 204 2,194 Intact 666 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2C/T Tubing Reel 11,500 407 2,194 Intact 666 30mm Hole 372 100mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 3C/T Injector Head 5,400 157 2,194 Intact 666 Intact 372 10mm Hole 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Dropped Anchor during running/retrieval 7,900 90.0 1,234 Intact 608 Intact 372 Intact 67 FB Rupture 22 FB Rupture 5 FB Rupture Case 2Impact from a broken anchor chain 50 kg/link 2.0 617 Intact 304 Intact 263 Intact 67 Intact 22 Intact 5 Intact No ReleaseImpact from anchor chain at touch down N/A 5.0 617 Intact 304 Intact 263 Intact 67 Intact 22 Intact 5 Intact No ReleaseSnag load from dragged anchor N/A 3,750 kN N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Case 10DSV Clump Weight Large 1,000 11.0 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseDSV Clump Weight Small 500 4.4 617 Intact 304 Intact 263 Intact 67 Intact 22 Intact 5 Intact No ReleaseImpact from a diving bell collision N/A Negligible N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact No ReleaseImpact from diving bell clump weight 3,000 18.0 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseImpact from diving bell drop weight 500 12.6 926 Intact 456 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseImpact from a ROV collision N/A Negligible N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact N/A Intact No ReleaseControl Pod 1,000 12.0 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseSubsea wireline BOP 1,000 13.8 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseSubsea wireline lubricator 900 5.7 2,194 Intact 666 Intact 372 Intact 67 Intact 22 Intact 5 Intact No ReleaseImpact from a vessel sinking 5,000 T 64,000 N/A FB Rupture N/A FB Rupture N/A FB Rupture N/A FB Rupture N/A FB Rupture N/A FB Rupture Case 10Impact from fishing gear N/A 45.0 1,234 N/A 608 N/A 372 N/A 67 N/A 22 N/A 5 N/A No ReleaseSnag load from fishing gear N/A 500 kN N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A No ReleasePull over load from fishing gear N/A 230 kN N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A No Release

Table 3 (continued)Potential for Rupture of Protected Subsea Pipework from Dropped Objects and Impact Scenarios



Rev D2

Summary Calculations for Tubular Dropped Object and Impact Analysis

Units Input 36" Casing 30" Casing 20" Casing 13.375" Casing

13.375" Casing

10.75" Casing

10.75" Casing

9.625" Casing

9.625" Casing

7" Liner 7" Liner

Type of lift none Y Single Single Single Single Bundle x 3 Single Bundle x 4 Single Bundle x 4 Single Bundle x 7External diameter m Y 0.914 0.762 0.508 0.340 0.340 0.273 0.273 0.244 0.244 0.178 0.178Wall thickness mm Y 38.1 25.4 15.9 12.2 12.2 11.4 11.4 12.0 12.0 10.4 10.4Nominal length (feet) ft Y 40 40 40 40 40 40 40 40 40 40 40Number of tubes in bundle none Y 1 1 1 1 3 1 4 1 4 1 7Number of tubes in length none Y 1 1 1 1 1 1 1 1 1 1 1Length m N 12.19 12.19 12.19 12.19 12.19 12.19 12.19 12.19 12.19 12.19 12.19Length forward from C of G m N 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096Length rearward from C of G m N 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.096Internal diameter of pipe m N 0.838 0.711 0.476 0.315 0.315 0.250 0.250 0.220 0.220 0.157 0.157Effective external diameter of pipe/bundle m N 0.914 0.762 0.508 0.340 0.703 0.273 0.773 0.244 0.692 0.178 0.533Weight in Air of pipe/bundle kg N 10051 5633 2352 1207 3620 900 3601 840 3360 522 3657Weight per unit length of pipe/bundle kg/m N 824.42 462.00 192.91 98.98 296.94 73.84 295.36 68.89 275.58 42.85 299.93Displacement of material in pipe/bundle m3 N 1.279 0.717 0.299 0.154 0.461 0.115 0.458 0.107 0.427 0.066 0.465Internal volume of pipe/bundle m3 N 6.73 4.84 2.17 0.95 2.85 0.60 2.40 0.47 1.86 0.24 1.65External volume of pipe/bundle m3 N 8.01 5.56 2.47 1.11 4.74 0.71 5.72 0.57 4.58 0.30 2.72Rotational inertia of pipe/bundle kg m2 N 124507 69772 29134 14948 44845 11151 44606 10405 41618 6471 45296Density kg/m3 N 7860 7860 7860 7860 7860 7860 7860 7860 7860 7860 7860Density of water kg/m3 N 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025Displacement of water of pipe/bundle kg N 1311 735 307 157 472 117 470 110 438 68 477Weight of pipe/bundle in water kg N 8741 4898 2045 1049 3148 783 3131 730 2922 454 3180Weight of internal volume of water kg N 6896 4964 2226 975 2926 614 2457 477 1908 242 1695External added mass kg N 8207 5699 2533 1133 4854 732 5861 587 4698 310 2793Total mass for acceleration and velocity kg N 23843 15562 6804 3158 10928 2129 11450 1794 9528 1007 7667Total mass for impact calculations kg N 25154 16296 7111 3315 11400 2246 11919 1904 9966 1075 8144Normal added mass coefficient none N 2.503 2.893 3.023 2.747 3.149 2.495 3.310 2.266 2.966 2.058 2.227Tangential added mass coefficient none N 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136Rotational added mass coefficient none N 2.503 2.893 3.023 2.747 3.149 2.495 3.310 2.266 2.966 2.058 2.227Normal drag coefficient none N 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000Tangential drag coefficient none N 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167Normal projected area m2 N 11.148 9.290 6.194 4.142 8.574 3.329 9.421 2.981 8.435 2.168 6.503Tangential projected area m2 N 35.024 29.186 19.458 13.012 26.935 10.458 29.597 9.364 26.500 6.810 20.430l/d ratio for added mass none N 13.33 16.00 24.00 35.89 17.34 44.65 15.78 49.87 17.62 68.57 22.86Added mass shape factor (alpha) none N 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00DELTA maximum end horizontal position m Y 32.59 33.25 44.09 51.75 41.36 54.18 43.57 53.31 42.88 59.34 36.26DELTA maximum end angular position degrees Y 2.15 1.18 0.29 0.52 0.72 0.46 0.75 0.42 0.31 0.17 0.54DELTA maximum horizontal end velocity m/s Y 0.61 0.80 0.75 0.77 0.77 0.76 0.67 0.75 0.76 0.69 0.75DELTA maximum vertical end velocity m/s Y 3.20 3.18 2.51 2.20 2.65 2.12 2.52 2.17 2.58 2.00 3.06DELTA maximum end angular velocity degree/s Y 1.89 1.06 0.49 0.39 0.65 0.29 0.34 0.26 0.51 0.07 0.50Maximum horizontal impact energy kJ N 4.68 5.21 2.00 0.98 3.38 0.65 2.68 0.54 2.88 0.26 2.29Maximum vertical impact energy kJ N 128.79 82.40 22.40 8.02 40.03 5.05 37.85 4.48 33.17 2.15 38.13Maximum resultant impact energy kJ N 133.47 87.61 24.40 9.00 43.41 5.70 40.52 5.02 36.05 2.41 40.42

Table 4Summary Calculations for Tubular Dropped Object and Impact Analysis



Rev D2


Units Input 5.5" Tubing 5.5" Tubing 5.5" Tubing 4.5" Tubing 4.5" Tubing 4.5" Tubing 6.625" Drill Pipe

6.625" Drill Pipe

5.5" Drill Pipe

5.5" Drill Pipe

5" Drill Pipe 5" Drill Pipe

Type of lift none Y Single Bundle x 7 Length x 3 Single Bundle x 7 Length x 3 Single Length x 4 Single Length x 4 Single Length x 4External diameter m Y 0.140 0.140 0.140 0.114 0.114 0.114 0.168 0.168 0.127 0.127 0.140 0.140Wall thickness mm Y 7.7 7.7 7.7 6.9 6.9 6.9 12.7 12.7 12.7 12.7 12.7 12.7Nominal length (feet) ft Y 40 40 40 40 40 40 31 31 31 31 31 31Number of tubes in bundle none Y 1 7 1 1 7 1 1 1 1 1 1 1Number of tubes in length none Y 1 1 3 1 1 3 1 4 1 4 1 4Length m N 12.19 12.19 36.58 12.19 12.19 36.58 9.45 37.80 9.45 37.80 9.45 37.80Length forward from C of G m N 6.096 6.096 18.288 6.096 6.096 18.288 4.724 18.898 4.724 18.898 4.724 18.898Length rearward from C of G m N 6.096 6.096 18.288 6.096 6.096 18.288 4.724 18.898 4.724 18.898 4.724 18.898Internal diameter of pipe m N 0.124 0.124 0.124 0.101 0.101 0.101 0.143 0.143 0.102 0.102 0.114 0.114Effective external diameter of pipe/bundle m N 0.140 0.419 0.140 0.114 0.343 0.114 0.168 0.168 0.127 0.127 0.140 0.140Weight in Air of pipe/bundle kg N 307 2148 920 223 1558 668 461 1844 339 1355 376 1505Weight per unit length of pipe/bundle kg/m N 25.16 176.15 25.16 18.26 127.80 18.26 48.79 48.79 35.84 35.84 39.83 39.83Displacement of material in pipe/bundle m3 N 0.039 0.273 0.117 0.028 0.198 0.085 0.059 0.235 0.043 0.172 0.048 0.192Internal volume of pipe/bundle m3 N 0.15 1.03 0.44 0.10 0.68 0.29 0.15 0.61 0.08 0.31 0.10 0.39External volume of pipe/bundle m3 N 0.19 1.68 0.56 0.13 1.13 0.38 0.21 0.84 0.12 0.48 0.14 0.58Rotational inertia of pipe/bundle kg m2 N 3800 26603 102610 2757 19301 74448 3430 219505 2520 161269 2800 179188Density kg/m3 N 7860 7860 7860 7860 7860 7860 7860 7860 7860 7860 7860 7860Density of water kg/m3 N 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025Displacement of water of pipe/bundle kg N 40 280 120 29 203 87 60 240 44 177 49 196Weight of pipe/bundle in water kg N 267 1868 800 194 1355 581 401 1603 295 1178 327 1309Weight of internal volume of water kg N 152 1061 455 99 694 298 155 621 79 314 99 398External added mass kg N 192 1724 575 128 1154 385 215 862 123 491 148 594Total mass for acceleration and velocity kg N 610 4652 1830 421 3203 1263 772 3086 496 1983 575 2300Total mass for impact calculations kg N 650 4932 1950 450 3407 1350 832 3327 540 2160 624 2497Normal added mass coefficient none N 2.118 2.297 2.118 2.022 2.186 2.022 1.804 1.804 1.594 1.594 1.659 1.659Tangential added mass coefficient none N 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136Rotational added mass coefficient none N 2.118 2.297 2.118 2.022 2.186 2.022 1.804 1.804 1.594 1.594 1.659 1.659Normal drag coefficient none N 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000Tangential drag coefficient none N 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167Normal projected area m2 N 1.703 5.110 5.110 1.394 4.181 4.181 1.590 6.360 1.200 4.800 1.320 5.280Tangential projected area m2 N 5.351 16.052 16.052 4.378 13.134 13.134 4.995 19.980 3.770 15.080 4.147 16.588l/d ratio for added mass none N 87.27 29.09 261.82 106.67 35.56 320.00 56.15 224.60 74.40 297.60 67.64 270.55Added mass shape factor (alpha) none N 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00DELTA maximum end horizontal position m Y 69.73 43.02 107.29 75.31 46.38 109.99 51.73 93.16 52.65 94.94 52.39 94.42DELTA maximum end angular position degrees Y 0.08 0.68 43.54 0.07 0.67 45.88 0.47 43.72 0.45 47.86 0.48 46.51DELTA maximum horizontal end velocity m/s Y 0.67 0.67 1.39 0.67 0.65 1.35 0.71 1.60 0.75 1.59 0.75 1.59DELTA maximum vertical end velocity m/s Y 1.73 2.65 2.43 1.63 2.49 2.32 2.20 3.09 2.17 3.10 2.18 3.10DELTA maximum end angular velocity degree/s Y 0.02 0.23 0.35 0.02 0.39 0.30 0.19 0.57 0.28 0.49 0.31 0.52Maximum horizontal impact energy kJ N 0.15 1.11 1.88 0.10 0.72 1.23 0.21 4.26 0.15 2.73 0.18 3.16Maximum vertical impact energy kJ N 0.97 17.32 5.76 0.60 10.56 3.63 2.01 15.88 1.27 10.38 1.48 12.00Maximum resultant impact energy kJ N 1.12 18.43 7.64 0.70 11.28 4.86 2.22 20.14 1.42 13.11 1.66 15.15

Table 4 (continued)Summary Calculations for Tubular Dropped Object and Impact Analysis



Rev D2


Units Input 10" Drill Collar

10" Drill Collar

8" Drill Collar

8" Drill Collar

6.5" Drill Collar

6.5" Drill Collar

Drilling Riser Drilling Riser Completion Riser

Completion Riser

Type of lift none Y Single Length x 4 Single Length x 4 Single Length x 4 Single Length x 2 Single Length x 2External diameter m Y 0.254 0.254 0.203 0.203 0.140 0.140 0.533 0.533 0.203 0.203Wall thickness mm Y 92.1 92.1 73.0 73.0 57.2 57.2 12.8 12.8 15.8 15.8Nominal length (feet) ft Y 31 31 31 31 31 31 50 50 45 45Number of tubes in bundle none Y 1 1 1 1 1 1 1 1 1 1Number of tubes in length none Y 1 4 1 4 1 4 1 2 1 2Length m N 9.45 37.80 9.45 37.80 9.45 37.80 15.24 30.48 13.72 27.43Length forward from C of G m N 4.724 18.898 4.724 18.898 4.724 18.898 7.620 15.240 6.858 13.716Length rearward from C of G m N 4.724 18.898 4.724 18.898 4.724 18.898 7.620 15.240 6.858 13.716Internal diameter of pipe m N 0.070 0.070 0.057 0.057 0.025 0.025 0.508 0.508 0.172 0.172Effective external diameter of pipe/bundle m N 0.254 0.254 0.203 0.203 0.140 0.140 0.533 0.533 0.203 0.203Weight in Air of pipe/bundle kg N 3479 13914 2218 8872 1101 4403 2503 5006 1001 2002Weight per unit length of pipe/bundle kg/m N 368.15 368.15 234.73 234.73 116.49 116.49 164.23 164.23 72.99 72.99Displacement of material in pipe/bundle m3 N 0.443 1.770 0.282 1.129 0.140 0.560 0.318 0.637 0.127 0.255Internal volume of pipe/bundle m3 N 0.04 0.14 0.02 0.10 0.00 0.02 3.09 6.17 0.32 0.63External volume of pipe/bundle m3 N 0.48 1.92 0.31 1.23 0.14 0.58 3.41 6.81 0.44 0.89Rotational inertia of pipe/bundle kg m2 N 25881 1656368 16501 1056088 8189 524124 48443 387545 15694 125555Density kg/m3 N 7860 7860 7860 7860 7860 7860 7860 7860 7860 7860Density of water kg/m3 N 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025Displacement of water of pipe/bundle kg N 454 1815 289 1157 144 574 326 653 131 261Weight of pipe/bundle in water kg N 3025 12100 1929 7715 957 3829 2177 4353 871 1741Weight of internal volume of water kg N 37 148 25 99 5 20 3164 6328 325 651External added mass kg N 491 1963 314 1256 148 594 3491 6981 456 912Total mass for acceleration and velocity kg N 3553 14211 2268 9070 1111 4442 8831 17663 1652 3304Total mass for impact calculations kg N 4006 16026 2557 10227 1254 5016 9158 18316 1782 3565Normal added mass coefficient none N 1.152 1.152 1.153 1.153 1.139 1.139 3.659 3.659 1.780 1.780Tangential added mass coefficient none N 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136 0.136Rotational added mass coefficient none N 1.152 1.152 1.153 1.153 1.139 1.139 3.659 3.659 1.780 1.780Normal drag coefficient none N 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000Tangential drag coefficient none N 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167 0.167Normal projected area m2 N 2.400 9.600 1.920 7.680 1.320 5.280 8.129 16.258 2.787 5.574Tangential projected area m2 N 7.540 30.159 6.032 24.127 4.147 16.588 25.538 51.076 8.756 17.512l/d ratio for added mass none N 37.20 148.80 46.50 186.00 67.64 270.55 28.57 57.14 67.50 135.00Added mass shape factor (alpha) none N 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00DELTA maximum end horizontal position m Y 21.89 50.35 24.68 59.50 29.38 70.37 50.53 67.74 50.08 76.54DELTA maximum end angular position degrees Y 0.33 11.65 0.34 24.16 0.36 38.78 0.69 0.32 0.27 15.45DELTA maximum horizontal end velocity m/s Y 0.67 2.75 0.67 2.47 0.65 2.25 0.71 0.71 0.71 1.71DELTA maximum vertical end velocity m/s Y 4.91 5.45 4.39 5.45 3.73 5.12 2.26 2.26 2.45 2.79DELTA maximum end angular velocity degree/s Y 0.38 2.27 0.24 2.18 0.29 1.61 0.22 0.13 0.12 0.93Maximum horizontal impact energy kJ N 0.90 60.60 0.57 31.20 0.26 12.70 2.31 4.62 0.45 5.21Maximum vertical impact energy kJ N 48.29 238.00 24.64 151.89 8.72 65.75 23.39 46.77 5.35 13.87Maximum resultant impact energy kJ N 49.19 298.60 25.21 183.09 8.99 78.45 25.70 51.39 5.80 19.09

Table 4 (continued)Summary Calculations for Tubular Dropped Object and Impact Analysis



Rev D2

Summary Calculations for Container Dropped Object and Impact Analysis

Units Input Container Mini Empty

Container Mini Full

Container Mini Full

Container 10' Empty

Container 10' Full

Container 10' Full

Container 20' Empty

Container 20' Full

Container 20' Full

General orientation none Y Horizontal Horizontal Vertical Horizontal Horizontal Vertical Horizontal Horizontal VerticalLength forward from C of G m N 1.15 1.15 1.69 1.52 1.52 2.28 3.05 3.05 5.07Length rearward from C of G m N 1.15 1.15 0.61 1.52 1.52 0.72 3.05 3.05 1.03Weight of object empty in air kg Y 1620 1620 1620 2000 2000 2000 3000 3000 3000Weight of contents in air kg Y 0 4380 4380 0 6000 6000 0 15000 15000Total weight in air kg Y 1620 6000 6000 2000 8000 8000 3000 18000 18000Material of object none Y Steel Steel Steel Steel Steel Steel Steel Steel SteelDensity of object kg/m3 Y 7860 7860 7860 7860 7860 7860 7860 7860 7860Material of contents none Y Steel Steel Steel Steel Steel Steel Steel Steel SteelDensity of contents kg/m3 Y 7860 7860 7860 7860 7860 7860 7860 7860 7860Length of object (longest side) m Y 2.30 2.30 2.30 3.00 3.00 3.00 6.10 6.10 6.10Width of object m Y 1.85 1.85 1.85 1.80 1.80 1.80 2.50 2.50 2.50Height of object (shortest side) m Y 1.59 1.59 1.59 1.80 1.80 1.80 2.50 2.50 2.50External volume of object m3 N 6.77 6.77 6.77 9.72 9.72 9.72 38.13 38.13 38.13Average of height and width for 2D object m N 1.72 1.72 1.72 1.80 1.80 1.80 2.50 2.50 2.50Ratio of height/width to length none N 0.75 0.75 0.75 0.60 0.60 0.60 0.41 0.41 0.41Displacement of object (empty) m3 N 0.21 0.21 0.21 0.25 0.25 0.25 0.38 0.38 0.38Displacement of material inside object m3 N 0.00 0.56 0.56 0.00 0.76 0.76 0.00 1.91 1.91Total displacement of object m3 N 0.21 0.76 0.76 0.25 1.02 1.02 0.38 2.29 2.29Rotational inertia of object kg m2 N 714 2645 2645 1500 6000 6000 9303 55815 55815Density of water kg/m3 N 1025 1025 1025 1025 1025 1025 1025 1025 1025Displacement of object in water kg N 211 782 782 261 1043 1043 391 2347 2347Weight of object in water kg N 1409 5218 5218 1739 6957 6957 2609 15653 15653Weight of internal volume of water kg N 6723 6152 6152 9702 8920 8920 38687 36731 36731External added mass falling horizontally kg N 11130 11130 11130 16559 16559 16559 69715 69715 69715External added mass falling vertically kg N 10471 10471 10471 15044 15044 15044 59008 59008 59008Total mass for acceleration and velocity kg N 19262 22500 22500 28000 32435 32435 111011 122099 122099Total mass for horizontal impact calculations kg N 19473 23282 23282 28261 33478 33478 111402 124446 124446Total mass for vertical impact calculations kg N 18815 22623 22623 26746 31964 31964 100695 113739 113739Normal added mass coefficient none Y 1.61 1.61 1.61 1.66 1.66 1.66 1.78 1.78 1.78Tangential added mass coefficient none Y 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51Rotational added mass coefficient none Y 1.61 1.61 1.61 1.66 1.66 1.66 1.78 1.78 1.78Normal drag coefficient none Y 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00Tangential drag coefficient none Y 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00Normal projected area m2 N 3.94 3.94 3.94 5.40 5.40 5.40 15.25 15.25 15.25Tangential projected area m2 N 2.94 2.94 2.94 3.24 3.24 3.24 6.25 6.25 6.25DELTA maximum end horizontal position m Y 60.19 29.70 42.00 65.65 30.98 3.76 117.03 39.06 11.29DELTA maximum end angular position degrees Y 0.06 0.08 84.18 0.06 0.21 82.71 36.33 0.67 86.65DELTA maximum horizontal end velocity m/s Y 0.66 0.66 1.37 0.66 0.66 -0.01 0.63 0.64 0.19DELTA maximum vertical end velocity m/s Y 1.85 3.56 4.21 1.76 3.51 4.64 1.84 3.13 4.93DELTA maximum end angular velocity deg/s Y 0.01 0.01 0.02 0.05 0.05 0.01 0.74 0.27 0.05Maximum horizontal impact energy kJ N 4.24 5.07 21.23 6.16 7.29 0.00 22.11 25.49 2.05Maximum vertical impact energy kJ N 33.32 147.53 200.49 43.77 206.23 344.08 188.58 609.59 1382.20Maximum resultant impact energy kJ N 37.57 152.61 221.72 49.93 213.52 344.09 210.69 635.08 1384.26

Table 5Summary Calculations for Container Dropped Object and Impact Analysis



Rev D2

Summary Calculations for Wireline & Coiled Tubing Dropped Object and Impact Analysis

Units Input W/L Reel & Control

Container

W/L Reel & Control

Container

W/L BOP W/L Lubricator Sections

C/T Control Container

C/T Control Container

C/T PSU Container

C/T PSU Container

C/T Reel C/T Injector Head

General orientation none Y Horizontal Vertical N/A N/A Horizontal Vertical Horizontal Vertical N/A N/ALength forward from C of G m N 1.71 2.74 0.50 5.50 1.71 2.74 1.83 2.93 2.31 3.04Length rearward from C of G m N 1.71 0.69 0.50 5.50 1.71 0.69 1.83 0.73 2.31 3.04Total weight in air kg Y 5000 5000 1000 600 5500 5500 6954 6954 11500 5364Average density of object kg/m3 Y 2000 2000 7860 7860 2000 2000 2000 2000 5000 7860Length of object (longest side) m Y 3.43 3.43 1.00 11.00 3.43 3.43 3.66 3.66 4.62 6.07Width of object m Y 2.46 2.46 0.40 0.13 2.46 2.46 2.46 2.46 3.35 2.07Height of object (shortest side) m Y 2.36 2.36 0.40 0.13 2.36 2.36 2.36 2.36 2.36 2.07External volume of object m3 N 19.92 19.92 0.16 0.18 19.92 19.92 21.25 21.25 18.29 25.99Average of height and width for 2D object m N 2.41 2.41 0.40 0.13 2.41 2.41 2.41 2.41 1.99 2.07Total displacement of object m3 N 2.500 2.500 0.127 0.076 2.750 2.750 3.477 3.477 2.300 0.682Total void space of object m3 N 17.42 17.42 0.03 0.10 17.17 17.17 17.78 17.78 15.99 25.31Rotational inertia of object kg m2 N 4899 4899 83 6050 5389 5389 7754 7754 20455 16475Density of water kg/m3 N 1025 1025 1025 1025 1025 1025 1025 1025 1025 1025Displacement of object in water kg N 2563 2563 130 78 2819 2819 3564 3564 2358 700Weight of object in water kg N 2438 2438 870 522 2681 2681 3390 3390 9143 4664Weight of internal volume of water kg N 17860 17860 34 104 17604 17604 18222 18222 16395 25939External added mass falling horizontally kg N 32778 32778 263 302 33942 33942 38867 38867 33454 47523External added mass falling vertically kg N 30838 30838 248 275 30838 30838 32897 32897 28316 40224Total mass for acceleration and velocity kg N 53075 53075 1166 928 54227 54227 60479 60479 58991 78126Total mass for horizontal impact calculations kg N 55638 55638 1297 1006 57046 57046 64043 64043 61348 78825Total mass for vertical impact calculations kg N 53698 53698 1281 978 53941 53941 58074 58074 56210 71526Normal added mass coefficient none Y 1.61 1.61 1.61 1.66 1.66 1.66 1.78 1.78 1.78 1.78Tangential added mass coefficient none Y 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51 1.51Rotational added mass coefficient none Y 1.61 1.61 1.61 1.66 1.66 1.66 1.78 1.78 1.78 1.78Normal drag coefficient none Y 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00Tangential drag coefficient none Y 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00Normal projected area m2 N 8.266 8.266 0.400 1.397 8.266 8.266 8.818 8.818 9.194 12.561Tangential projected area m2 N 5.811 5.811 0.160 0.016 5.811 5.811 5.811 5.811 3.960 4.281DELTA maximum end horizontal position m Y 64.44 48.47 21.70 231.60 61.19 45.27 55.92 39.73 44.25 51.58DELTA maximum end angular position degrees Y 0.02 -92.12 0.03 -2.03 0.01 -90.41 0.07 -86.42 -0.13 0.07DELTA maximum horizontal end velocity m/s Y 0.66 0.42 0.66 -2.09 0.66 0.90 0.66 0.84 0.68 0.65DELTA maximum vertical end velocity m/s Y 1.68 2.02 4.56 1.99 1.76 2.11 1.92 2.38 2.19 1.89DELTA maximum end angular velocity deg/s Y 0.00 3.49 0.00 0.34 0.01 -3.07 0.00 -1.47 -0.03 0.00Maximum horizontal impact energy kJ N 12.12 4.74 0.28 2.20 12.42 21.85 13.95 22.59 14.18 16.65Maximum vertical impact energy kJ N 78.52 109.55 13.48 1.99 88.35 120.08 118.04 181.38 147.12 140.79Maximum resultant impact energy kJ N 90.63 114.29 13.77 4.19 100.78 141.92 131.99 203.98 161.30 157.44

Table 6Summary Calculations for Wireline & Coiled Tubing Dropped Object and Impact Analysis



Rev D2

Heavy Goods Handling OperationMinimum Horizontal Safe

Handling Distance from Nearest Point on Subsea Facilities

Approximate Weight

BOP running and retrieval on drilling riser 28 m 140 Tonnes

Subsea tree and LRP / EDP running and retrieval on workover riser 28 m 120 Tonnes

LRP/EDP running and retrieval on workover riser 28 m 90 Tonnes

Subsea tree / shipping skid over the side crane loading and handling 28 m 35 Tonnes

LRP / EDP / EDP lift & test cap / test & shipping skid over the side crane loading and handling 28 m 31 Tonnes

Tree cap / shipping skid over the side crane loading and handling 28 m 5 Tonnes

Tree cap running tool / test or shipping skid over the side crane loading and handling 28 m 11 Tonnes

Surface tree / adaptor joint / riser spiders and miscellaneous tools in surface tree half height shipping basket over the side crane loading and handling 28 m 23 Tonnes

Completion riser sections (7 off) and surface joint in riser joints shipping basket over the side crane loading and handling 28 m 23 Tonnes

THRT / THOAJ / check tool in THOAJ shipping basket over the side crane loading and handling 28 m 13 Tonnes

TH / etc in TH shipping basket over the side crane loading and handling 28 m 6 Tonnes

Riser pup joints in riser pup joints shipping basket over the side crane loading and handling 28 m 6 Tonnes

Completion riser stress joint / tension joint shipped in stress joint / tension joint shipping skid over the side crane loading and handling 28 m 9 Tonnes

4 tools shipping and storage skid complete with tools over the side crane loading and handling 28 m 5 Tonnes

Subsea tree / BOP test stand over the side crane loading and handling 28 m 6 Tonnes

Subsea tree debris cap over the side crane loading and handling No Precautions Required 2.5 Tonnes

Workover control panel over the side crane loading and handling 28 m 6.5 Tonnes

Workover umbilical reel over the side crane loading and handling 28 m 10.5 Tonnes

Tubing hanger umbilical reel over the side crane loading and handling 28 m 5 Tonnes

Workover control system storage container over the side crane loading and handling 28 m 3.5 Tonnes

Bundle of 4½ “ tubing over the side crane loading and handling No Precautions Required 1.6 Tonnes

Bundle of 5½ “ tubing over the side crane loading and handling No Precautions Required 2.2 Tonnes

Coiled tubing reel over the side crane loading and handling 42 m 11.5 Tonnes

Coiled tubing injector head over the side crane loading and handling 42 m 5.5 Tonnes

Drum of electric line cable over the side crane loading and handling 28 m 20 Tonnes

Table 7Dropped Objects and Impacts to be Protected Against by Procedural Controls



Rev D2

Heavy Goods Handling OperationMinimum Horizontal Safe

Handling Distance from Nearest Point on Subsea Facilities

Approximate Weight

Mud logging unit over the side crane loading and handling 42 m 18 Tonnes

10’ container over the side crane loading and handling 42 m 8 Tonnes

20’ container over the side crane loading and handling 42 m 18 Tonnes

Anchor transfer between vessels during mooring and unmooring 200 m 10 Tonnes

Piggy back anchor over the side crane loading and handling 28 m 10 Tonnes

Single length 6" drill collars over the side crane loading and handling No Precautions Required 1.1 Tonnes

Bundle of 3½ “ drill pipe over the side crane loading and handling No Precautions Required 1.5 Tonnes

Rig winch over the side crane loading and handling 28 m 25 Tonnes

Mud pump over the side crane loading and handling 28 m 33 Tonnes

Wireline unit over the side crane loading and handling 28 m 11 Tonnes

Pressure control skid over the side crane loading and handling 28 m 8 Tonnes

Completion basket (54 ft) over the side crane loading and handling 28 m 10 Tonnes

Steam exchanger (20 ft) over the side crane loading and handling 28 m 10.5 Tonnes

Pressure skid (12 ft) over the side crane loading and handling 28 m 6 Tonnes

Heat exchanger (24 ft) over the side crane loading and handling 28 m 10 Tonnes

Pressurised laboratory (16 ft) over the side crane loading and handling 28 m 10 Tonnes

Monitoring cabin (10 ft) over the side crane loading and handling 28 m 5 Tonnes

Air compressors (14 ft) over the side crane loading and handling 28 m 6 Tonnes

Mega-Flow separator (part 1) over the side crane loading and handling 28 m 11.7 Tonnes





Gun basket (30 ft) over the side crane loading and handling 28 m 7 Tonnes

Tool house (12 ft) over the side crane loading and handling 28 m 5 Tonnes

Table 7Dropped Objects and Impacts to be Protected Against by Procedural Controls



Rev D2

Probability of Impact for Dropped BOP

0.0

0.0

0.0

0.0

0.0

0.1

1.0

0 5 10 15 20 25

Horizontal Distance between Drop Point and Edge of Target (m)

Pro

bab

ility

of

Imp

act

per

Dro

p

Direct Impacts

Toppling Impacts

Figure 1Probability of Impact for Dropped BOP



Rev D2

Probability of Impact for Dropped Tree

0.0

0.0

0.0

0.0

0.0

0.1

1.0

0 5 10 15 20 25

Horizontal Distance between Drop Point and Edge of Target (m)

Pro

bab

ility

of

Imp

act

per

Dro

p

Figure 2Probability of Impact for Dropped Tree



Rev D2

Drop Angle versus Horizontal Distance Travelled for 9.625" Casing in Still Water

0

10

20

30

40

50

60

1.0E

-10

1.0E

-09

1.0E

-08

1.0E

-07

1.0E

-06

1.0E

-05

1.0E

-04

1.0E

-03

1.0E

-02

1.0E

-01

1.0E

+00

Drop Angle from Vertical (degrees)

Ho

rizo

nta

l Dis

tan

ce T

rave

lled

(m

)

Drop Angle versus Impact Energy for 9.625" Casing in Still Water

0

10

20

30

40

50

60

70

1.0E

-10

1.0E

-09

1.0E

-08

1.0E

-07

1.0E

-06

1.0E

-05

1.0E

-04

1.0E

-03

1.0E

-02

1.0E

-01

1.0E

+00


Imp

act

En

erg

y (k

J)

Drop Angle versus Impact Angle for 9.625" Casing in Still Water

-10

0

10

20

30

40

50

60

70

80

90

1.0E

-10

1.0E

-09

1.0E

-08

1.0E

-07

1.0E

-06

1.0E

-05

1.0E

-04

1.0E

-03

1.0E

-02

1.0E

-01

1.0E

+00


Imp

act

An

gle

fro

m H

ori

zon

tal (

deg

rees

)

Figure 3Behaviour of 9.625” Casing when Dropped at Near Vertical Angles through Still Water



Rev D2

Impact Probability versus Distance From Drop Point for Floating Containers

10

100

1,000

10,000

1E-071E-061E-051E-041E-031E-02

Probability of Impact

Dis

tan

ce f

rom

Dro

p P

oin

t (m

)

20' Large Container

10' Small Container

Mini Container

Figure 4Impact Probability versus Distance from Drop Point for Floating Containers



Rev D2

0.1

1

10

100

1000

1 10 100 1000 10000

Impact Energy (kJ)

Dro

pp

ed O

bje

ct W

eig

ht

in A

ir (

Ton

nes

)

Rupture of all pipew ork14" dia and less






Approximate w orstcase correlation ofdropped object w eightversus impact energy

(20' Container)

Rupture of all pipework 14" & less






Figure 5Correlation of Dropped Object Weight versus Impact Energy



Rev D2

Moonpool

Minimum Rig Dimensions

Average Rig Dimensions

Maximum Rig Dimensions

Anchor No 122½° ± 5°

Anchor No 3112½° ± 5°

Anchor No 4157½° ± 5°

Anchor No 5202½° ± 5°

Anchor No 6247½° ± 5°

Anchor No 7292½° ± 5°

Anchor No 8337½° ± 5°

Rig Heading0° (relative)

10m 20m 30m 40m 50m


Schematic Layout ofGeneric Drilling Rig

33.33% 33.33%Typical craneloading area

Typical craneloading area

33.33%Non typical craneloading area

Figure 6Schematic Layout of Generic Drilling Rig



Rev D2

33.33% 33.33%30T 15T

33.33%33.33% 30T15T C

C

Moonpool


Anchor No 3112½° ± 5°

Anchor No 4157½° ± 5°

Anchor No 5202½° ± 5°

Anchor No 6247½° ± 5°

Anchor No 7292½° ± 5°

Anchor No 8337½° ± 5°


10m 20m 30m 40m 50m

Schematic Layout ofSedco Sovreign Explorer

Drilling Rig used forPre-Drilling Operations


Figure 7Schematic Layout of Sedco Sovereign Explorer Drilling Rig used for Pre-Drilling Operations



Rev D2

33.33%33.33% 30T15T 33.33% 33.33%30T 15T

Moonpool

33.33%

33.33%

18T

60T


Anchor No 3112½° ± 5°

Anchor No 4157½° ± 5°

Anchor No 5202½° ± 5°

Anchor No 6247½° ± 5°

Anchor No 7292½° ± 5°

Anchor No 8337½° ± 5°



10m 20m 30m 40m 50m

Schematic Layout ofSedco Drillstar DrillingRig used for Initial WellCompletion Operations

Figure 8Schematic Layout of Sedco Drillstar Drilling Rig used for Initial Well Completion Operations



Rev D2

INSERT FIGURE 9

Figure 9Subsea Centre Seabed Layout Showing Dropped Object Boundaries



Rev D2

28m

Moonpool




10m 20m 30m 40m 50m

Typical 28m Dropped ObjectDrop Out Zone from

Moonpool on Generic DrillingRig




Figure 10Typical 28m Dropped Object Drop Out Zone from Moonpool on Generic Drilling Rig



Rev D2

Moonpool




10m 20m 30m 40m 50m

Typical 28m Dropped ObjectDrop Out Zones from Portand Starboard Cranes on

Generic Drilling Rig




Figure 11Typical 28m Dropped Object Drop Out Zones from Port and Starboard Cranes on Generic Drilling Rig



Rev D2

Moonpool




10m 20m 30m 40m 50m

Typical 42m Dropped ObjectDrop Out Zones from Portand Starboard Cranes on

Generic Drilling Rig




Figure 12Typical 42m Dropped Object Drop Out Zones from Port and Starboard Cranes on Generic Drilling Rig



Rev D2

INSERT FIGURE 13

Figure 13Subsea Centre Seabed Layout Showing Typical Severe Weather Stand Off Positions for Sedco Drillstar



Rev D2

INSERT FIGURE 14

Figure 14Subsea Centre Seabed Layout Showing Typical Emergency Stand Off Positions for Sedco Drillstar


subsea dropped object and layout study

Documents

dropped objects

dropped equipment

dropped object protection

dropped anchors

dropped containers3

potential dropped object

dropped tools

dropped bop3