Seadrill – Head Officeunderside of the rig floor and spray outwards. The flow partially subsided...

SEA.010.001.0001

SEA.010.001.0001

Seadrill Management AS Report

Seadrill – Head Office

3 02.02.10 Open Final TT DG IMS

2 7.12.09 Open Review DG DG n/a

1 23.11.09 Open Interim Report D Kelly D. Gouldin G. Ross n/a

0 11.09.09 Open Preliminary D. Kelly n/a n/a

Rev Date Status Purpose Prepared by Checked Approved

Title: Investigation Report

Blow-out Montara Platform – Fri 21 Aug 2009

Document category: Administrative document

Document No.: Not assigned Document type: Report

Contract no.: Issued by: Duane Kelly Q&HSE Manager – Jack-up Division Investigation Group Leader

To be destroyed:

No. of pages:

© This document is copyright and shall not be reproduced without the permission of Seadrill. This document is not for distribution.

1

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To: Ian Shearer, Senior Vice President – Jack-up Division

cc: David Gouldin, Operations Manager – Jack-up Division

From: Duane Kelly – Q&HSE Manager Jack-up Division

Date: 02 February 2010

SUBJECT: INVESTIGATION REPORT

BLOWOUT ON MONTARA PLATFORM – FRI 21 AUG 2009

Mandate for investigation:

Mandate for investigation authorised by David Gouldin, Operations Manager.

Investigation was conducted to arrive at root causes and to provide

recommendations to prevent recurrence.

Investigation group presented preliminary report on Aug 27th 2009, final report

issued 02 February 2010.

This report is a revised report after review by Seadrill Operations Manager

and Well Engineer Consultant.

Investigation Group:

Name Role

Duane Kelly Investigation Group Leader

Tim Marsh Investigation Group Member

Technical Review Team:

Name Role

David Gouldin Technical Review Team Leader

Bruce Worthington Technical Review Team Member

Graham Ross Technical Review Team Member

Tom Trendall Technical Review Team Member

2

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Definitions:

AD - Assistant Driller CEO - Chief Executive Officer CCF - Change Control Form (PTTEP Aust) COO - Chief Operating Officer DHSE - Director HSE (Stavanger) DTP - Day Toolpusher HSE - Health, Safety & Environment JSA - Job Safety Analysis Maint. Supv. - Maintenance Supervisor MLS - Mud line Suspension MOC - Management of Change (Seadrill) NTP - Night Toolpusher OIM - Offshore Installation Manager Op Mgr. - Operations Manager (Jack-up Division) PCCC - Pressure Containing Corrosion Cap SMS - Safety Management System SOP - Standing Operating Procedures SVP - Senior Vice President – Jack-up Division WA - West Atlas WHP - Well Head Platform

Personnel Interviewed

Rig Manager – West Atlas - Donald Millar Rig Superintendent (OIM) (On duty) - Phillip Trueman Toolpusher (Day) - Bart Kok Toolpusher (Night) - David Jones Maintenance Supervisor - Iain Stoddart Senior Mechanic - Didier Lesca Barge Master - Michael Glen Driller - David Horne Driller / Safety Coach - Dillwyn Davies Assistant Driller - Robert Bradford Derrickman - Luke Taylor Lead Floorman - Stuart Louth Floorman - Shane Howlett

TKM Wellhead Engineer - John Penny TKM Wellhead Engineer - Brad Ryder

Well Construction Manager PTTEPAA - Craig Duncan Drilling Superintendent PTTEPAA - Chris Wilson Day Drilling Supervisor - Paul O’Shea Night Drilling Supervisor - Lindsay Wishart Extra Drilling Supervisor - Brian Robinson Logistics Coordinator - Mathieu Higgins

3

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Contents

1.0 Executive Summary Page 6

2.0 Introduction Page 9

3.0 Operational Standards Page 28

3.1 Change Control Page 28

3.2 Well Control Page 32

3.3 Pre-Spud meetings Page 34

4.0 Well Discussion Points Page 36

5.0 Emergency Procedures – West Atlas Page 39

6.0 Evaluation of Witness Accounts Page 40

7.0 Barriers Page 41

8.0 Causal Analysis Page 45

9.0 Corrective Actions Page 47

10.0 Conclusion Page 49

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Appendices

1. Incident photographs Page 51

2. Witness Statements – Summary Page 53

3. PTTEP Change Control Orders Page 79

4. 9 5/8” Cementation Page 81

5. PTTEP Document Timeline Page 82

6. Sequence of Operations Page 83

7. H1 & H1-ST1 Well History Excerpt Page 84

8. PTTEP Drilling Supervisor Statement Page 85

9. Planned Sequence of Tiebacks – Phase 1B Page 86

10. Deck Designations Page 89

5

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1.0

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Executive Summary

From January to April 2009, the Montara Platform wells were batch drilled in

two sets prior to the installation of the platform topsides.

Each production well was drilled with a horizontal section into the reservoir,

set and cemented with 9 5/8” casing with 9 5/8” casing displaced to inhibited

seawater. The wells were temporarily abandoned (suspended) and West Atlas

relocated to open water locations until installation of the jacket topsides were

completed.

The suspension plan included a change in program to install 13 3/8” and 9

5/8” Pressure Containing Corrosion Caps (PCCC’s) to the top of two wells at

surface at the MLS hanger. The PCCC’s replaced an original shallow set 9

5/8” cement abandonment plug. The PCCC’s sealed the 13 3/8” and 9 5/8”

annulii. The PCCC’s were covered by a 20” trash cap.

The West Atlas returned to Montara WHP on 19th Aug 2009 to tie-back the 5

suspended wells. The approved Drilling and Completion Program (dated

30/06/09) called for batching the tie-backs by casing string (all 20” then 13

3/8” then 9 5/8”).

The first well for tieback was H1. The 20” trash cap was removed and well top

visually inspected by a PTTEP Drilling Supervisor. A 9 5/8” PCCC was

installed but not a 13 3/8” PCCC. A 13 3/8” PCCC was required as per

PTTEP’s suspension program and in compliance with the PTTEP barrier

policy. Significant scale and corrosion was seen on the 13 3/8” MLS hanger

internal thread with cement debris on top of the 9 5/8” PCCC. The absence of

a 13 3/8” PCCC had allowed corrosion to the internal casing thread.

PTTEP drilling personnel changed the 20’ tie-back program in order to run a

clean-up brush on the 13 3/8” MLS hanger thread to be performed prior to

running the 20” tieback casing. Running a 13 3/8” brush required removing

the 9 5/8” PCCP. The 9 5/8” PCCC was removed, brush run, 13 3/8” threads

cleaned and brush laid down. The 20” tie-back program on H1 resumed

without re-installing the 9 5/8” PCCC. Upon completion of H1 20” tie-back, a

6

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loose hatch cover was placed over the new 20” casing on H1 and rig skidded

to next 20” tieback.

At 0530hrs Friday 21st August 2009, the rig was retrieving the 20” tie-back cut

off from well H4 when H1 kicked. An estimated 40bbls of fluids and gas flowed

from the well with sufficient force to strike the underside of the rig floor falling

back onto and contaminating the WHP helideck with an oily fluid. This kick

was short-lived but activated gas alarms, emergency response activity and

muster of personnel onboard.

Following the subsidence of this activity and an assessment that the

immediate danger had passed, the all-clear was ordered, musters released

and emergency response stood down. A decision was made to run a

Halliburton RTTS packer into well H1 to secure the well. This required laying

down a 20” casing cut-off held in the derrick hoisting assembly from well H4

then skidding the rig over well H1.

Skidding activity was about to begin when at 0723hrs, the well kicked again

blowing a column of fluid and gas, with sufficient force as to again strike the

underside of the rig floor and spray outwards. The flow partially subsided after

a few seconds but this was momentary and it quickly resumed blowing out at

force.

Management of emergency response activities were in accordance with the

rig emergency response plans, culminating in the safe abandonment of all

personnel from the drilling rig.

The nominated Investigation team from Singapore office attended the Seadrill

Operations Office, Perth on Monday 24th August 2009, to commence an

investigation.

Following examination of all evidence and conducting root cause analysis

activity, the following causal factors were identified as being the most

significant (a full record of causal factors is made in the main body of report);

(Note: A root cause of a consequence is any basic underlying cause that was

not in turn caused by more important underlying causes).

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Root Cause:

• Non-compliance of PTTEP Well Construction Standards and barrier policy

for long term well suspension.

Causal Factors:

• Failure to install a 13 3/8” PCCC on H1 in March 2009

• Failure to recognise the significance of the absence of a 13 3/8” PCCC on

H1 at commencement of tie-back operations in August 2009.

• Failure to recognise the significance of removing 9 5/8” PCCC on H1

without containment equipment in place.

• Failure to replace 9 5/8” PCCC after cleaning 13 3/8” threads

• Lack of a Pre-Spud meeting or Risk Assessment prior to commencing the

tie-back programme.

• Change control procedure for modification to H1 tieback programme

circumvented.

Conclusion:

Non-compliance with the barrier policy for suspended wells as set out in

PTTEP Well Construction Standards is the root cause of the blowout.

Additional contributory causes included

Departure from programmed equipment inclusions in the well (no 13 3/8”

PCCC),

Non-compliance with PTTEP Change Control process (Tie back programme

changed without formal documentation in place),

Lack of Risk Assessment and Pre-spud meetings for the Tie-back programme

Poor awareness as to the risks associated with removing barriers from a

potentially live well without containment in place.

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2.0 Introduction

The purpose of this investigation is to establish the root causes and causal

factors that led to the blowout on Montara Platform requiring the emergency

evacuation of West Atlas.Friday 21st August 2009

Activity at the time:

West Atlas returned to Montara platform after a 4 month absence. West Atlas

pinned on bottom and started rigging up at 1400hrs on Wed 19 August 2009,

with the first of the batched re-entry work being undertaken on Well H1-ST1

(hereafter noted as H1) from about 0600hrs on Thursday 20 August 2009.

Factual account of incident and consequences:

On the 6th January 2009, the ‘Montara GI, H1 & H4 (Batch Drilled) Drilling

Program (Document No. TM-CR-MON-B-150-00001)’, was issued as an

approved and controlled document by Coogee Resources (now PTTEP), for

the immediate work to be undertaken by West Atlas on Montara Platform,

located in the southern Timor Sea region (off northern West Australia).

H4H2 H3

H1 GI

West

Atlas

The works on Montara jacket commenced January 18th 2009, with H1 being

the first well spudded. At this time, the suspension diagram and plan for well

H1 was a cemented 9 5/8” casing shoe at 3373m and a shallow set cement

9

SEA.010.001.0010

I® CoogeeResources ACJL7 Suspension Diagram

Manta ... H1

508mm (20") Corrosion Cap

o 508mm (20") Landing Ring al- 2S.2m J ~

, T Cement Plug from 160m to 115m 508mm (201 Casing Shoe al- lSO.7m

, ]

,

, , 340mm (13 318") Carog Shoe at - 1617m

, ,

, 244mm (9 518; Casing Shoe at - 3373

~TOSC.·.LI'


SEA.010.001.0010

plug from 160m to 115m; inhibited seawater above and below this plug as

illustrated below.

10

SEA.010.001.0011

® CoogeeResources AC/L7 Montara GI Suspension Diagram

Q 508mm (201 Corrosioo Cap J ~ I l 340mm {13 3161 Pressure I=?: Containing Corrosion Cap QI 508mm (20; l anding Ring al- 28,Zm 244mm {9 5181 Pressure

Containing Corrosion Cap II 1\ lc J'

~ Cement Plug from 160m to 115m , T • •

~ ~ 508mm (20") Casing Shoe at - I SO.7m • .< ~ ~

5 6 ., ~ ~ ~ c • ~ n 0 0 0

:c • ~ • , ~ , , N

2

" ~ • r • T • T • • • 340mm (13 318") Casing Shoe al-1618m ~ ~ , • • 0

, ,

T

244mm (9 518'1 Casing Shoe at - 2884m

NOTTOSCALE

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Well H4 was also programmed to be suspended in this manner, though well

GI was different in that it was planned to use pressure containing corrosion

caps at 13 3/8” and 9 5/8” (additional to cemented casing shoe and inhibited

seawater), instead of the shallow cement plug, to suspend the well.

11

SEA.010.001.0012

CoogeeResources

50Smm (20") CM""'" Cop J

ACIL7 Montara H2

Suspension Diagram

o l

508mm (20") Landing Ring at - 26.2m

Cement Plug from 160m to 115m

508mm (20") Casing Shoe at - 149.4m

~ , • w .li ~

~ " .. ~

~ ~ 0 • ~ 0

§ "-• " , ~

340mm (13 318") Casing Shoe at - 1613m , N • ,

TopolT .. 2711m

244mm (9 518") Casing Shoe at - 3146m

HOT TO SCALE


SEA.010.001.0012

During January, a decision was taken that two additional wells would be

added to the program, being Wells H2 & H3. Both of these wells were to be

suspended using the shallow cement plug (i.e. H1 & H4).

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On the 23rd January 2009, a PTTEP Change Control Order No 1was issued

requiring a change to the 9 5/8” cementing program on H1 increasing the

vertical height of TOC in the 9 5/8” annulus from 30m to 69m above top of

reservoir (Annex 3 Item 1)

On the 30th January 2009, a PTTEP Change Control Order No 3 was issued

requiring a further change in the cementing program of the 9 5/8” casing

bringing the TOC 50m inside the shoe of the 13 3/8” casing to eliminate the

addition of a 13 3/8” PCCC at the surface MLS hanger (Annex 3 Item 2)

On the 5th of March 2009, Well H1 reached TD.

On the 7th March 2009, there is an entry in the IADC Daily Drilling Report for

Well H1 noting:

“RIH w/ retaining pressure cap t/ 28m, apply 7 1/4 LHT, apply 2000

ft/lbs, release f/ cap POOH L/O R/T”

This entry indicates that well H1 was suspended with an unspecified Pressure

Containing Corrosion Cap. Subsequent information confirmed it as the 9 5/8”

PCCC.

On the 12th March 2009, a PTTEP Change Control Order No 6 was issued

requiring a change to the suspension plan by using a 9 5/8” and 13 3/8”

PCCC on H1 and eliminating the planned shallow set cement plug in the bore

of the 9 5/8” casing (Annex 3 Item 3):

The suspension configuration attached to Change Control Order No 6 is

shown over.

The Daily Drilling Report reflects that only one PCCC was fitted (9 5/8”), while

the later Change Order stipulates both 9 5/8” and 13 3/8” PCCC’s would be

fitted with the stated purpose of “Improved well integrity during suspension

and re-entry operations.”

The 9 5/8” PCCC was installed 5 days prior to Change Order No 6 being

issued.

13

It is notable that this Change Control Form was only approved some 5 days

after the change had been undertaken (or partially undertaken) as reflected in

the IADC report (07/03/09).

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Neither PTTEP nor Seadrill drilling personnel on-site for the suspension of

Well H1 could provide any reason for the ‘missing’ 13 3/8” PCCC and the

failure to comply with Change Control Order No 6 to fit such a cap onto H1.

Of the 5 wells drilled and suspended during the initial drilling phase, the ‘As

Built’ suspension diagrams show wells H1 and GI had 9 5/8” and 13 3/8”

PCCC’s fitted with no shallow set 9 5/8” cement plug. The remaining Wells

H2, H3 and H4 had 13 3/8” PCCC’s installed in conjunction with a shallow set

9 5/8” cement plug (160m – 115m).

The Drilling Program for Well H1 called for the 9 5/8” casing to be pressure

tested to 4000psi and left with inhibited seawater inside. The IADC entry for

cementing the H1 9 5/8” casing records the plug bumping and casing tested to

4000psi but that floats failed as pressure was bled off and 16.5bbls of fluid

were returned at surface. 16.5bbls were re-pumped back into the casing but

without bumping the plug. Pressure was held for 3hrs to allow cement to set

(Appendix 4)

The concern in the 9 5/8” cement job (designed to place cement 50m inside

the 13 3/8” shoe) was that after the initial successful casing pressure test of

4000psi the float equipment failed as pressure was bled off. 16.5bbls of

inhibited seawater were returned to the cement unit. The cement unit was

then used to pump 16.5bbls back into the 9 5/8” casing and pressure was held

until the cement set. As it took 9.25bbls to press the fluid to 4000psi then the

actual backflow through the floats would have been 7.25bbls or thereabouts.

By pumping 16.5 bbls back without impedance would indicate the plug leaked

and the shoe was overdisplaced by 9.25bbls allowing the shoe to become

wholly wet giving a theoretical bottom of cement in the annulus approximately

60ft above the casing shoe.

On the 21st April 2009, West Atlas completed the suspension of all five

programmed wells in accordance with directions provided on-site and moved

from Montara jacket to open water locations. This concluded Phase 1

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It is confirmed later that Well H1 was suspended with only the following well

control barriers in place,

o Cemented 9 5/8” casing job back to and inside the 13 3/8” Casing shoe

• 9 5/8” Pressure Containing Corrosion Cap

• Inhibited Seawater column inside 9 5/8” casing

In summary, only one barrier was in place internally (9 5/8” PCCC) and one

barrier assumed in place externally via the 9 5/8” cement job.

After the completion of Phase 1, the original Batch Drilling Program (Montara

H1, GI & H4) issued 6 Jan 2009 and the subsequent Batch Drilling Program

(Montara H2 & H3) issued 3 Feb 2009, were revised to include ‘As-Built’ well

data and merged with the new program for the tie back work in Phase 1B.

This new document became Montara Phase 1B Drilling & Completion

Program Rev.0 issued 30th June 2009.

The sequence of batch tie backs is noted in Appendix 6. The work required in

this program was a systematic batching program beginning with tying back the

20” casing strings commencing with H1.

Also captured in the Montara Phase 1B Drilling & Completion Program Rev.0

were Well Status and Well History data from the first phase of drilling (January

2009 – April 2009). Excepts from this document for well H1 and H1-ST1 are

noted in Appendix 7

Of note from this record; the following facts are recorded by PTTEP

(Australasia) as being completed relative to Well H1;

• Side-track 9 5/8” casing run at 90.3deg into reservoir

• Failure of float / plug bumped and pressure maintained until cement set • Installation of 9 5/8” PCCC

• Installation of 13 3/8” PCCC

• Installation of 20” Trash Cap

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While PTTEP refer to the installation of the 13 3/8” PCCC a number of times

throughout this Program, the physical state of the well at the time of re-entry

demonstrates that this was not the case.

On Wed 19th August 2009, West Atlas returned to Montara Platform to

commence Phase 1B of the Program

During that day, Drilling Supervisor Paul O’Shea, compiled and issued

‘Montara Platform Forward Plan 1b – 20” Tie-back’, which detailed the

program from a point where West Atlas was 1km off Montara Platform through

to the commencement of well re-entries and the systematic tie-back of the 20”

Casing per the approved Program. The 20” tie-back activity was to begin with

H1 then go to Well GI then H4, H2 and H3. The tie-back activity involved

rough hot cutting and precision cold cutting of the 20” Casing.

This issued Drillers instruction was consistent with the approved Drilling &

Completions Program Rev 0 though expanding on some detail and not

including offline activity detail.

At approximately 0600hrs on Thursday the 20th August 2009, the rig skidded

over Well H1 and the Trash Cap was removed, as per the Montara Phase 1B

Drilling & Completion Program Rev.0 and the ‘Montara Platform Forward Plan

1b – 20” Tie-back’ instruction (issued 19/08/09).

At this time the following senior personnel were onboard West Atlas;

• Craig Duncan – PTTEP Well Construction Manager (i.e. Drilling Manager)

• Paul O‘Shea – PTTEP Day Drilling Supervisor (Day Companyman)

• Lindsay Wishart – PTTEP Night Drilling Supervisor (Night Companyman)

• Brian Robinson – PTTEP Extra Drilling Supervisor

• Mathieu Higgins – PTTEP Drilling Engineer / Logistics Coordinator

• Phil Trueman – Seadrill Offshore Installation Manager (OIM)

• Bart Kok – Seadrill Day Toolpusher

• David Jones – Seadrill Night Toolpusher

Upon removal of the 20” trash cap with the tugger winch, the stumps of the 13

3/8” and the 9 5/8” were exposed and readily visible within. During this

campaign, an extra Drilling Supervisor was onboard (Brian Robinson) and it

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was he who was at the MLS deck level and who checked the well immediately

after the trash cap was removed. His observations were noted in a provided

statement (Appendix 8) which indicated he

o Removed H1 trash cap. o Inspected H1 stump and observed powdery cement pieces on

top of corrosion cap and between 13 3/8 x 9 5/8’’ annulus. He assumed that the cement had fallen from the BOP and diverter system when removed

o Cleaned around 9 5/8” corrosion cap and annulus. Noted bubbles discharging from the 13 3/8 x 9 5/8’’ annulus although no hydrocarbon smell or gas detector reading.

o Gas detector readings performed periodically at the MLS all with zero readings.

o There was no oil at surface and no flow evident from the well. o Paul O’Shea also inspected the annulus and was satisfied all

was OK. o Cleaned and greased the 20’’ threads and replaced the “O” ring. o Attempted to clean the threads on 13 3/8’’ stump with wire brush

with little success, due to the presence of rust and scale build up.

o Informed Paul O’Shea and he revised the forward plan after discussion with Craig Duncan and informed Driller and Toolpusher to pull the 9 5/8’’ corrosion cap and run brush to clean the 13 3/8’’ threads.”

Senior Drilling Supervisor Paul O’Shea made the following observation and

gave the following recollection of the decision and change approval process:

o Casing was full and no flow reported, well was static.”

o Brian Robinson and myself informed Craig Duncan and agreed to make a BA51L brush run – to do this we needed to remove the 9⅝” corrosion cap. All agreed.

o I then informed the drill floor as to the change in plans. They laid out the 20” joint at which time Mat (Logistics), Assistant Driller and Crane Operator organized Corrosion Cap R/R tool, BA51L Brush tool and x/o to rig floor.

o I went inside and generated a supplementary forward plan (instruction to drillers) sequencing the change in operations (this plan was to be done and then continue with the original forward plans) (I think the supplementary was before point 7). At this

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stage I talked to Chris Wilson in Perth and discussed the change in plan and why.

o Took forward plans up to the rig floor – discussed with Dave Horne and Bart Kok, (on-tour Driller and Toolpusher).

This sequence of events is validated through interviews with Senior Seadrill

personnel

In a subsequent conversation onshore, the Well Construction Manager Craig

Duncan explained the normal Change Process as either originating with the

Drilling Supervisor or the Drilling Superintendent, the Change Control Form

then completed and subsequently passed to him for approval. The approved

Change Request is then distributed to all Program holders per the controlled

distribution list.

The significant points from the sequence of ‘Change’ activity relative to H1 on

the morning of 20th August are:

o No importance attached to the fact that the programmed 13 3/8” PCCC was missing from the well.

o The OIM was not party to this decision process and only found out when the hard copy supplementary plan was delivered to the rig floor.

o The process was undertaken directly between the Drilling Supervisor and the Well Construction Manager onboard (approved verbally), with the Drilling Superintendent Chris Wilson (onshore) being informed just prior to the delivery to the rig floor of the revised ‘Supplementary Plan’.

o The Rig Manager Donald Millar was not party to this change process.

At about 1100hrs on Thursday 20th August 2009, the ‘Montara Platform

Forward Plan #1b – 20” Tie back supplementary plan 20th Aug 09 Vers 2.0’

was delivered to the Driller and Toolpusher on the rig floor. This

supplementary plan detailed a diversion from the approved Montara Phase 1B

Drilling & Completion Program Rev.0, 20” tieback batching as follows;

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Montara Platform Forward Plan #1b – 20” Tie back supplementary plan 20th Aug 09 Vers 2.0:

“Unfortunately there is some scale build up on the 13⅜” MLS on H1 ST1. We need to clean this off. The follow points should be done before running the 20” conductor (Point 7 of the main forward plan).

1. P/U Corrosion cap running tool (ensure it has the plunger/pressure bleed off installed)

2. RIH and latch onto 9⅝” Corrosion cap (J-Slot) – Record any trapped pressure on stand pipe, bleed any pressure down via the choke.

3. Remove corrosion cap by rotating 8-9 turns clockwise with 15003500kft.lbs torque.

Note: DO NOT have any persons at the 20” stump level on the platform during this operation.

4. POOH with corrosion cap and running tool

5. P/U BA51L brush.

6. RIH with cleaning brush. Screw in TDS on second stand.

7. When located in 13⅜” MLS (Have some one down there to guide in and confirm heights)

8. Slowly turn at 10rpm and 50-100gpm.

9. POOH just above and have Brian confirm threads are clean

10.POOH and go back to main plan Point 7”

There is no inclusion or discussion of the re-installation of the 9 5/8” Pressure

Containing Corrosion Cap immediately following completion of the Brush job.

At about 1130hrs, the Corrosion Cap Running / Retrieval Tool was run in the

hole with the Top Drive made up to the stand (pressure control through the

IBOP back to the standpipe pressure gauges) to enable the pressure to be

monitored and safely controlled if required.

The Corrosion Cap Running and Retrieving Tool consists of a main body with

a drill pipe box up and a cylindrical bottom with internal J-slots. These slots

are designed to engage the torque pins on the mudline corrosion cap with

right hand rotation. An internal probe, located inside the bottom of the tool,

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opens the corrosion cap check valve as the running tool sets down over the

corrosion cap stem. Any pressure retained by the corrosion cap is vented

through the check valve into the drill pipe running string. Elastomers provide a

seal between the running tool and corrosion cap stem when the running tool is

stabbed over the mandrel.

Corrosion Cap R/R Tool

At this time, contrary to Step 3 of the Supplementary Plan, Drilling Supervisor

Brian Robinson and Seadrill A.D Rob Bradford were at the MLS level (20”

stump level), checking for audible signs of pressure release through the check

valve. Choke & Standpipe pressures were monitored for 2 mins and no

positive pressure detected.

At the time of this pressure monitoring, the DP and Kelly hose did not contain

any fluid (the jumper hose was not yet connected)

At 1150hrs, the 9 5/8” PCCC was unscrewed and retrieved back to the rig

floor. Seawater was visible in the 9 5/8” bore.

Drilling Supervisor Brian Robinson made the following observations at this

time:

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o Observed that the well was stable and gas detector showed zero

reading. Remained at MLS level and observed. The only smell

discharging from the well was pungent dirty water smell. No flow, no

bubbling, zero gas readings inside 9 5/8’’ observed throughout

entire operations.

After racking back the R/R Tool, the activity at well H1 reverted to the original

approved plan for the 20” tie-back and 20” casing was run.

Between 1500 – 1700hrs, the hot cut of the 20” Casing was undertaken (1m.

above the Mezzanine deck) and the excess 20” Casing laid out.

The rig was skidded over well GI for the continuation of the approved 20”

tieback program.

An excerpt from the programmed activity to follow the completion of the 20”

tie-backs is included in Appendix 9. The published program is quite clear in

the systematic removal of the intended 13 3/8” cap and installation of the slip

and seal assembly, followed by the identical routine in relation to the 9 5/8”.

The end result would have seen the controlled removal of each Pressure

Containing Corrosion Cap, then replaced by the seal assembly.

22

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Subsequently, over the next 12hrs, the 20” Tie-Back program was undertaken

on wells GI and H4. The cold cut on well H4 20” Casing was completed at

about 0500hrs on Friday 21st August 2009.

The cut-off joints of the 20” casing were still hanging in the derrick at 0535hrs.

At 0536hrs, there was a short duration discharge from well H1 of

approximately 40bbls of fluids plus visible gas vapor. This discharge was at

sufficient pressure to knock the deck cover from the top of the stump, pass

upwards from the rough-cut 20” stump 1m above the Mezzanine deck, up

through the open hatch of the WHP helideck level up through the rig sub

structure to reach the underside of the Rig Floor.

Observations at the time were that there was no evidence of seawater,

cuttings, rocks or other debris laying on the WHP helideck where the majority

of the 40bbls collected.

Drilling Supervisor Brian Robinson made the following observations at this

time:

o “The way the fluid was discharging was a distinct vertical column and it was falling back into the centre of the column which gave me the impression that it was unloading from the 13 3/8 x 9 5/8’’ annulus. Within 5 seconds the fluid had reached the underside of the rig floor and the gas alarms activated. The fluid itself looked like oil and no sign of the inhibited seawater pumped into the well prior to suspension.”

A gas monitor was used to take reading at the WHP helideck level

immediately after this discharge and the LEL reading was at 75% (note that

the atmosphere is considered hazardous if LEL >10% - OSHA).

The discharge triggered the Gas / Fire Alarm and all emergency response

requirements were satisfied, including muster of crews and activation of the

Control Room.

Following what was thought to be the well ‘bridging’ and no further discharge,

the ‘all-clear’ was sounded and a subsequent meeting by Senior PTTEP and

Seadrill personnel onboard decided that the course of action would be to lay

23

SEA.010.001.0024

SEA.010.001.0024


down the 20” cutoff from H4 still held in the blocks and then skid back over to

Well H1 in order to run a RTTS Packer.

At about 0723hrs, while two personnel were under the rig floor on the

Cantilever walkways attending to skidding tasks, Well H1 came in a second

time, this time with greater force and in a continuous columned stream,

striking the underside of the rig floor and with a visible volume of gas vapor

accompanying the fluids.

The gas emissions triggered the emergency alarms again and all personnel

mustered at their muster points in the Galley for Lifeboats #1 and #2 or other

designated muster locations (i.e. Control Room).

Within the Galley, witnesses (Witness statements pp 61 and 67) reported that

the personnel mustered in the associated with Lifeboat #2 became restless

and ‘heated’ and moved outside to muster at their Lifeboats ‘Boat Station’

muster point.

24

SEA.010.001.0025

SEA.010.001.0025


During this period, the assessment by the Senior Drilling personnel in the

Control Room (Seadrill and PTTEP) was that the well was not going to bridge

(refer Craig Duncan comments ERG Log 0935hrs 210809 “Casing to

reservoir means no real chance of well bridging off”) and that all non-essential

personnel should be evacuated. At this time a list of ‘essential’ personnel was

drawn up, comprising minimum crew required to enable skidding and running

of the RTTS packer should the well abate (assigned to Lifeboat #3).

Simultaneously, the direction was given for all mustered groups to now go to

the Lifeboat muster positions and await further instructions. It was shortly

after this that Brian Robinson went to both musters and extracted the

nominated ‘essential’ personnel, directing them to the Control Room.

The direction was then issued for all non-essential personnel to board

lifeboats and abandon the rig.

Approximately 5-10mins later, the decision was taken in the Control Room

that nothing more could be done, all ‘essential personnel’ would also

evacuate.

The following issues arose during this abandonment phase:

• Assigned Coxswains were removed from musters as part of ‘essential

crew’, leaving no qualified Coxswains.

• Due to the increased air-gap (90’ instead of 57’), when the Lifeboats (#1 &

#3) reached about 20’ from water, the winch brake had crept on due to

additional weight and not enough tension being applied to the launch

cable. This was rectified by increasing pull on the cable. It was not a

mechanical or equipment failure.

• Lifeboat #2 would not initially start and the power (recharge) cable had to

be plugged back in to enable motor start.

• The hook releases on Lifeboat #1 failed to release when activated from the

mechanism inside the lifeboat and at least one hook required manual

release by opening of a hatch and physically manipulating the hook

release.

25

SEA.010.001.0026

SEA.010.001.0026


All three lifeboats successfully moved to a safe location away from the rig and

the proceeded to the Stand-by vessel Lady Audrey, where they boarded and

were later transferred to the Construction Barge Java Constructor. Helicopter

transfers then took place to allow final transfer back to Darwin.

Onshore Darwin, Seadrill and TMS personnel coordinated personnel welfare

response.

26

SEA.010.001.0027

SEA.010.001.0027


Notification Time Line:

Fri 21 August 2009:

0535hrs – First Blow-out occurred

0540hrs – RM advised

0723hrs – Second Blow-out occurred

Singapore Time:

0550hrs – OIM informed Rig Manager (Perth)

0552hrs – Rig Manager informed Operations Manager (Singapore)

0554hrs – Operations Manager informed Snr. VP Jack-up Division (+1hr

Singapore)

0607hrs – NOPSA informed by Rig Manager Donald Millar (returned call @

0730am)

0600hrs – CEO informed (Singapore time)

0615hrs – VP HSEQA informed (Singapore time)

27

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SEA.010.001.0028


3.0 Operational Standards

The over-riding document stipulating regulatory and operational standards for

the operation of West Atlas on Montara Platform is the Safety Case, as

approved by the Australian Government body, the National Offshore

Petroleum Safety Authority (NOPSA).

While this Safety Case comprises of contributions from both Seadrill and

PTTEP, Seadrill is deemed under law to be the ‘Registered Operator’ and as

such, holds primary responsibility for compliance under this approval to

operate.

3.1 Change Control:

The requirements for Management of Change are referred under PTTEP Well

Construction Management Framework (ID: D41-502432-FACCOM). The

initiating responsibility lays with the PTTEP Drilling Superintendent, both for

preparation of the Change Request and for the associated compliance with

the Well Construction Standards (i.e. engineer change in accordance with the

Standard, control risk management activity and complete formal program

revision for issue to all Drilling Program holders following approval).

Accounts provided by the PTTEP Drilling personnel onboard West Atlas

(including the PTTEP Well Construction Manager) was that this process of

28

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SEA.010.001.0029


change control was complied with in relation to well H1 changes to program.

Approval given verbally by the PTTEP Well Construction Manager while on-

site was also considered to be in accordance with the Standard, by verbally

appraising of the Drilling Superintendent Chris Wilson although after the fact.

While PTTEP senior management considered that this process was sufficient

for the change process undertaken for well H1, the following facts should be

considered;

The Drilling Superintendent is the initiator of this change process following or

independent to the on-site Drilling Supervisor. He is the controlling party in

order to enforce a consistency in process and to provide input / justification in

accordance with the Standards requirements.

The change request process is required to be presented formally to the Well

Construction Manager, approved and immediately following that, transmission

of that signed hardcopy Change Order to all holders of controlled copies of the

Drilling & Completions Program. These holders include the OIM and the Rig

Manager.

While this is the formal practice, historic practice has been that upon the

initiation of a change request (especially when that change presents

increased risk), the Drilling Superintendent will contact the Rig Manager and

discuss the proposed change. Depending on circumstances of the proposed

change, this discussion will then progress to the Seadrill Operations Manager

(Singapore) for further deliberation and input into the risk management and

mitigation requirements.

Given that Seadrill is the registered operator of West Atlas in accordance with

the safety case and has a duty of care for personnel and company assets, this

is a proper and expected flow of collaborative activity.

An examination of Rig Manager records showed that no Change Control

Forms related to any Montara Platform activity (Phase 1 or 2) were evident on

file as distributed by PTTEP Document Control. Interview with the Rig

Manager confirmed the non-receipt of any Change Control forms from

29

Montara Phase 1B – Drill

SEA.010.001.0030

SEA.010.001.0030


PTTEP, as required for Controlled Copy holders (Copy No#12 below), though

the Rig Manager did confirm that he was party to discussions with the Drilling

Superintendent on proposed changes on irregular occasions.

Montara GI, H1 & H4 (Batch Drilled) Drilling Program

Document Number: TM-CR-MON-B-150-00001

Page 2:

ing & Completion Program

30

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SEA.010.001.0031


Document Number: TM-CR-MON-B-150-00003

Page 2 :

While the Change process undertaken onboard West Atlas on the 20 Aug

2009 in respect to Well H1 was loosely in accordance with the PTTEP

Standard and included the approval (verbal) of the Well Construction

Manager, the simple gaining of this approval does not make it correct. The

circumvention of critical elements i.e. Drilling Superintendent’s lack of

involvement from outset and subsequent communication with the Rig

Manager; was a serious flaw in what actually occurred and contributed to the

subsequent outcome.

31

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SEA.010.001.0032


3.2 Well Control:

It is accepted industry standard that to satisfy well control integrity, two

independent proven barriers must be in place. It is also accepted that a

hydrostatic column may also provide a barrier but this is only legitimate during

drilling operations and is in addition to the minimum ‘two proven barrier’

requirement.

It is clearly agreed and set out in the Safety Case and associated Safety Case

Revision i.e. Bridging Document (between Seadrill and PTTEP) that in respect

to Well Control, the PTTEP Well Construction Standards (ID: D41-502433

FACCOM) is the primary standard and that which is used in all PTTEP Well

design and Program formulation.

The following excerpts from this Standard outline PTTEP’s requirement for

well control Barriers:

32

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SEA.010.001.0033


It is clear that all wells on Montara Platform were classified as ‘Long Term

Suspensions’ in accordance to the definitions provided in this PTTEP

Standard. These standards require two permanent tested barriers installed in

annulus and well bore above any hydrocarbon zone or overpressured zone.

Well H1 was suspended with the following well control barriers in place:

• Casing cement job back to and inside the 13 3/8” Casing shoe

• 9 5/8” Pressure Containing Corrosion Cap

• Inhibited Seawater

Comparing these conditions against the standards for permanent barriers set

by PTTEP (Long Term Suspension) and subject to Safety Case inclusion, we

find the following;

• There was no pressure tested cement plug inside 9 5/8” casing

• There was no permanent packer installed

• There was no cemented casing with a proven TOC in place (no cement

bond logs were run and the existing cemented casing was assumed to

have integrity based on hole volume / cement volume calculations).

• There was as yet no Hanger Packer installed.

• There were as yet no Tubing Seals installed

• There was as yet no Annular Master Valve installed

In respect to Well H1 the requirement for two permanent tested barriers

installed in the annulus and well bore above any hydrocarbon or pressured

zone was therefore not satisfied.

33

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SEA.010.001.0034


3.3 Pre-Spud Meetings:

The PTTEP Well Construction Management Framework (ID: D41-502432

FACCOM) Standard outlines specific positional requirements for conduct of

Pre-Spud meetings upon the re-entry of a well.

The following are excerpt from this Standard, which clearly specify the

required actions from the following personnel. The Well Construction

Manager is expected to have synonymous responsibilities.

Drilling Superintendent Duties:

Drilling Engineer Duties:

34

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SEA.010.001.0035


Drilling Supervisor (Companyman) Duties

All Seadrill and PTTEP personnel interviewed, state that no Pre-spud meeting

was held prior to the commencement of operations on Thursday 20 August

2009 (i.e. the re-entry into the first well H1)

The failure to prepare for this activity and then conduct a briefing could have

contributed to the failure to recognize the non-conformity within the well

(absence of the 13 3/8” PCCC) and engage in correct evaluation and risk

management. Notwithstanding this possible contribution, it was also an

example of inadequate management where the communication of information,

competent instruction and re-familiarization of personnel is a critical element

of program preparation and stipulated as a PTTEP Standard for that reason.

There was no evidence of Senior Drilling personnel having a re-familiarization

with the Drilling & Completions Program, including the Seadrill OIM (holder of

Controlled Copy #13).

35

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SEA.010.001.0036


4.0 Well Discussion Points

9 5/8” Shoe - Float failure and no subsequent pressure test:

After the successful pressure test of the 9 5/8” casing to 4000psi and the

subsequent failure of the floats which allowed the cement to flow back into the

casing, no further test was possible as the plug did not bump again after

pumping 16.5 bbls. This volume of fluid pumped, without bumping the plug,

should have raised concerns of the possibility of a wet shoe and possible

remedial cementation to correct.

Cement Job – 9 5/8” shoe to 50m inside 13 3/8” Casing

In the PTTEP Well Construction Standards (ID: D41-502433-FACCOM), the

following definition is provided:

Good Oil-field Practice:

All those things that are generally accepted as good and safe in the carrying

on of exploration for petroleum, or in Operations for the recovery of petroleum,

as the case may be.

It is considered good oilfield practice to provide for a 10% variation in average

hole size when calculating open hole excess volumes for the design of casing

cementation, especially in such soft (sand), porous (22.1% and 19.5%

average porosity) and permeable (2600md and 700md) formations (Ref: TM

CR-MON-B-150-00001 Rev 2 - Montara Batch Drilling Program, Section 4.3).

In the case of Montara Platform, there are a number of recorded indicators

(“major losses encountered in Lower Johnson and upper Puffin zones - from

1706.5m” ref p.15 Montara Phase 1B Drilling & Completion Program Rev.0),

that indicate the unpredictability of the formation through which the 9 5/8”

casing was set.

The PTTEP Well Construction Standards (ID: D41-502433-FACCOM)

provides a clear expectation of what is considered “Good Oilfield Practice”

when it comes to cementation or cement plug jobs, as follows:

36

SEA.010.001.0037


SEA.010.001.0037

The following open-hole excess volumes should be used for the design of

casing cementation or cement plugs:

Cementing Environment Excess Slurry Volumes

Structural Casing and conductor strings 300% of nominal hole size

Hole Size 406mm or 445mm (No Calliper log available) 50% of nominal hole size

1. Other Hole Sizes (No calliper log available) Minimum 25% of assessed hole size

2. All casing sizes (2 - arm calliper log or acoustic calliper) 20%

3. All casing sizes (4 - arm calliper log) 10% of the integrated hole volume

Casing strings (except those placed by jetting or driving) shall be cemented as

follows:

String Requirements

Conductor � Cemented to seabed

Surface � ≥ 450m above the shoe, or � to the seabed if the string

SEA.010.001.0038

SEA.010.001.0038


There have been at least two documented comments related to the integrity of

the annulus cement jobs

Communication in H1 13 3/8” x 9 5/8” annulus:

Observation of Bubbles seen in 13 3/8” x 9 5/8” annulus by Drilling Supervisor

following the removal of Trash Cap (Thurs 20 Aug 2009) – Statement Brian

Robinson):

Evidence of gas bubbling in Well GI while being suspended during Phase One

“The 244mm (9-5/8”) casing was run and set at 2880m MD, where the plugs

did not bump however the floats held. The casing was backed out at the MLS

and a pressure containing corrosion cap was installed. Some time later, gas

was observed at surface to be bubbling up the 244mm (9-5/8”) x 340mm (13

3/8”) annulus – it was suspected that this gas was migrating from a small sand

within the Woolaston formation. Future wells had 244mm (9 5/8”) casing

centralisers run +/-100m across this sand, and the lead cement volume

increased, ensuring this sand was isolated.”

Communication between Wells H4 and GI, Phase 1 Drilling (Jan – Apr 2009):

Several statements made by drilling personnel regarding ‘communication’

between the wells during drilling, including one specific recount of

communication between Wells H4 and GI during drilling operations.

38

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SEA.010.001.0039


5.0 Emergency Procedures – West Atlas – discussion points

The evacuation of West Atlas concluded with all personnel correctly

accounted for and removed from the rig to a place of safety on adjacent

vessels without harm or injury.

Full evacuation from a drilling rig is a rare event and abandonment is not

performed as a standard drill. Abandonment drills do not include boarding or

launching lifeboats based on lessons learned from the past. Abandonment is

an exercise discussed at drill musters and described on the Station Bill.

Seadrill now has an opportunity of putting actual lessons learned into practice.

The West Atlas Station Bill reflected many other stations bills in that it

identified various types of emergency, the different alarm signals for each

emergency, the duties of each individual in each of those emergencies with

accompanying drawings, footnotes and instructions for personnel.

Feedback following the evacuation highlighted several areas where the

Station Bill could be improved including terminology, roles for designated

personnel, mismatch of on/off duty personnel to designated roles and

allocations and availability of coxswains.

Further, muster checkers could not always remain with mustered personnel as

additional requirements were made of them as designated essential

personnel. This weakened the command, control and communication function

leading to some indiscipline of mustered personnel.

In addition, training allocation and training currency require re-examination.

39

SEA.010.001.0040

SEA.010.001.0040


6.0 Evaluation of Witness Accounts

Witness accounts were generally open and forthright with few instances of

conflicting information. Where this did occur, it was not of a critical nature and

more understandably confusion, resultant from the nature of the event.

PTTEP were requested by Seadrill to allow interview of the offshore PTTEP

personnel but this request was denied, however offshore PTTEP personnel

did provide written statements (Appendix 2 PTTEP). These statements were

detailed and entirely consistent with the accounts given by Seadrill personnel,

both in relation to pre and post blowout actions.

Seadrill personnel were cooperative and transparent upon interview and

follow ups.

40

SEA.010.001.0041

SEA.010.001.0041


7.0 BARRIERS

MTO = Man, Technology and Organisation.

Barriers which failed:

MAN

M1 Concentration

• Lack of awareness of well ‘as-built’ specs vs actual state

• Lack of knowledge of approved Montara Phase 1B Drilling & Completion Program Rev.0 (June ’09)

M2 Work Performance

Phase One (Jan – April 2009)

• Deviation from approved program without required approval, consultation or

risk management processes followed (introduction of PCCC’s into

suspension program as recorded on IADC records but Change Approval

issued 5 days after the event)

• Deviation from approved plan and the change made was not in compliance

with subsequent Change Approval (13 3/8” & 9 5/8” Caps approved for

installation on suspension but only 9 5/8” cap installed)

• Non-compliance with Well Construction Standards (insufficient Barriers)

• Non-compliance with Well Construction Management Framework (Change

Request process inadequate)

Phase 1B (Aug 2009)

• Deviation from approved plan without required consultation or risk

management processes followed (supplementary plan to remove 9 5/8”

PCCC and run brush)

• Non-compliance with Well Construction Standards (insufficient Barriers)

• Non-compliance with Well Construction Management Framework (No Pre-

Spud meeting held)

• Non-compliance with Well Construction Management Framework (Change

Request process inadequate)

41

SEA.010.001.0042

SEA.010.001.0042


M3 Communication • No communication within PTTEP (Phase 1) when 13 3/8” PCCC was not

available at well suspension stage (no action taken to implement corrective

action or address risk management requirements and make authorized

Change Request to mitigate)

• No communication within PTTEP (Phase 1) when 13 3/8” PCCC not

installed (as-built drawings produced in incorrect state and Montara Phase

1B Drilling & Completion Program Rev.0 subsequently flawed)

• No explanation by PTTEP to Seadrill regarding non-compliance with

approved Drilling Program and non-installation of 13 3/8” PCCC (at end of

Phase 1).

• No communication of well condition change (not in compliance with ‘as

built”) - between PTTEP and Seadrill onsite (Phase 1B)

• No communication of well condition change (not in compliance with ‘as

built”) - between PTTEP and Seadrill onshore (Phase 1B)

• No communication of Well H1 Program change (Supplementary Plan Vers

2.0) to Rig Manager by PTTEP Drilling Superintendent

• No communication of Well H1 Program change (Supplementary Plan Vers

2.0) to Rig Manager by OIM

• Seadrill Well Control Manual inadequate (insufficient guidance regarding

barriers)

M4 Attitude towards requirements

• Lack of familiarity of PTTEP Drilling Personnel with PTTEP Well

Construction Standard – Barriers (unaware of requirements evidenced

through non-compliance)

• Lack of familiarity of Seadrill Supervisors with PTTEP Well Construction

Standard – Barriers (unaware of existence of PTTEP Well Construction

Standard – Barriers although is a primary standard stipulated in Vessel

Safety Case)

• Lack of familiarity (Seadrill Drilling Personnel) with Seadrill Well Control

Manual (unaware of content)

42

SEA.010.001.0043

SEA.010.001.0043


TECHNOLOGY:

T1 Design / Ergonomics

• State of well suspension flawed through failure to comply with approved

program and install 13 3/8” PCCC (Phase 1)

• Well design and state of suspension flawed through failure to comply with

Well Construction Standard (Barriers)

• Program change (Supplementary Plan Vers 2.0 20.08.09) and resultant well

state not in compliance with Well Construction Standard (Barriers)

• 9 5/8” Casing Cementation not in accordance with PTTEP Well Construction

Standard

T2 Technical State

• ‘As-Built’ drawings and approved Montara Phase 1B Drilling & Completion

Program Rev.0 (June 2009) were incorrect

ORGANISATION:

O1 Competence

• Personnel on board did not know the Standards to which they were

expected to comply (Well Construction Standard & Well Construction

Management Framework – per Safety Case)

O2 Procedures

• Well Control Manual (Seadrill) insufficient detail or guideline

O3 Planning Phase 1 & 1B Drilling Program

• Drilling Program changed without correct process followed or risk

management competently performed

• Evidence of Program changes without engaging PTTEP Change Request

process.

43

http:20.08.09

SEA.010.001.0044

SEA.010.001.0044


• Program changes implemented prior to receipt of signed approval and

communication with all stakeholders (Controlled copies - Drilling &

Completion Program, including Rig Manager and OIM)

O4 Supervision

• PTTEP Drilling Supervisor and Well Construction Manager failure to comply

with Procedure (Change Request)

• PTTEP Drilling Superintendent and Drilling Supervisor failure to lead and

conduct Pre-Spud before re-entry of wells

• OIM failure to notify Seadrill management (Rig Manager) of Program

changes.

• OIM failure to ensure compliance with Standards (PTTEP Well Construction

Standard - Barriers)

O5 Maintenance

• Nil

O6 Priority

• There is no evidence that Change Control had priority within the operation

O7 Work Environment

• No evidence of any contributory factors.

44

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SEA.010.001.0045


8.0 Causal Analysis

Root Cause/s:

• Non-compliance with PTTEP Well Construction Standards (Barriers)

Over displacement of 9 5/8” primary cement job leaving shoe wet and

having no barrier integrity

Removal of and failure to re-fit 9 5/8” PCCC – August 20th 2009

Failure to install 13 3/8” PCCC – March 7th 2009

Failure to recognise this anomaly as a warning signal and investigate

barrier conditions on H1

Contributing Causes:

• Inadequate knowledge and supervision - over displacement of 9 5/8”

casing cementation

• Inadequate knowledge and supervision in rig up and test for pressure

below 9 5/8” PCCC

• Inadequate Communication (13 3/8” Cap not installed) – PTTEP & Seadrill

• Inadequate Communication (Program changes) –Seadrill OIM / RM

• Inadequate Supervision (PTTEP) - Change Control & well integrity

• Inadequate Supervision – Seadrill (Change Control & well integrity

oversight and compliance)

45

SEA.010.001.0046

SEA.010.001.0046


• Inadequate Supervision (non-recognition of anomaly [missing 13 3/8” cap]

when H1 Trash Cap removed) – PTTEP Drilling Supervisors

• Inadequate Knowledge (PTTEP & Seadrill) – Drilling Program

• Inadequate Knowledge (PTTEP & Seadrill) – PTTEP Well Construction

Standards (Barriers)

• Non-compliance with approved Change Control (install 13 3/8” PCCC)

• Non-compliance with PTTEP Well Construction Management Framework

(Change Control process including risk management and mitigation

processes – non-installation of 13 3/8” PCCC and alternative measures

reqd.)

• Non-compliance with PTTEP Well Construction Management Framework

(Pre-spud meeting and crew briefing / re-familiarisation with program)

• Unnecessary Program change Well H1 – Supplementary Plan 20 Aug

Vers.02 – not required to be done at that time and no need to deviate from

20” tie-back Program

• Unnecessary Program change Well H1 – Supplementary Plan 20 Aug

Vers.02 – no consideration for re-installation of 9 5/8” PCCC following

completion of the Brush run.

• Inaccurate compilation of Montara Phase 1b Drilling & Completion

Program Rev: 0 (program and as-built diagram still included 13 3/8”

PCCC)

46

SEA.010.001.0047

SEA.010.001.0047

9.0 Corrective action(s)

Immediate West Atlas:


No. Corrective Action By / Evidenced By By Status

1. Evacuation of Rig OIM 21- Aug-09 Closed

Immediate West Triton


1. Review Seadrill Change Management process. Programme changes to be formally issued to OIM from Rig Manager

Operations Manager

Seadrill Dispensation Form from NOP

30 Sept 09 Closed

2.

Familiarisation – Snr. Drilling (Seadrill) personnel with Safety Case Revision i.e. Bridging Document and requirement for Risk Assessments and Pre-Job Meetings

Rig Manager Bridging Doc / SCR

submitted to OIM from Singapore

30 Sept 09 Closed

3. Familiarisation – Snr. Drilling (Seadrill) personnel with PTTEP Well Construction Standard (relevant parts)

Rig Manager PTTEP Drilling

Program issued to OIM

30 Sept 09 Closed

4. Familiarisation – Snr. Drilling (Seadrill) personnel with barrier verification responsibilities

Rig Manager PTTEP Well

Construction change control form issued to

OIM

30 Sept 09 Closed

5. Checklist of Programme Issues and Changes to be retained by Rig Manager

Rig Manager Seadrill dispensation

form from NOP / PTTEP Well

Construction change control form issued to

OIM

30 Sept 09 Closed

6.

Gather personnel in Darwin and conduct Safety Inductions with all rig, client and third party personnel attending West Triton

Rig Manager Pre Spud / DWOP

10 Sept 09 Closed

7. Conduct DWOP on relief well Rig Manager /

Client Pre Spud / DWOP

10 Sept 09 Closed

47

SEA.010.001.0048

SEA.010.001.0048


8. DWOP focus on Management of Change and Well Control Rig Manager /

Client Pre Spud / DWOP

10 Sept 09 Closed

Long Term:

No. Corrective Action By By Status

1. Review Seadrill Well Control Manual in general and barrier controls in particular Corporate 31 Jan 10 Open

2. Produce and disseminate a case study on this incident internal Seadrill QHSE

Manager 31 Jan 10 Open

Emergency Response Corrective Actions:


1. Review Rig Emergency Manuals ensure compliance with Seadrill standards QHSE

Manager 31 Jan 10 Open

2. Review all rig’s Station Bills in relation to usability, alarm response and personnel assignments

Marine Sup 31 Jan 10 Open

3. Review Coxswain job positions QHSE Manager 31 Jan 10 Open

48

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SEA.010.001.0049


10.0 Conclusion

The high level failure leading to the blowout of the Montara H1–ST1 well, the

environmental damage caused and the destruction of West Atlas was the

consequence of a failure of PTTEP to meet its documented management

system standards regarding barrier policy. The component failures that led to

the high level failure included:

A well design philosophy,incorporating minimum requirements in cost and

time.

Changes to the cementation programmes (barriers) that could have been

decided during the planning phases (under planned). These changes

extended only to meet minimum theoretical practices and were not tested to

confirm whether barrier practices were met or otherwise.

A deviation from a pre-planned programme in using newly available surface

set PCCC’s instead of normal cement suspension plugs for the temporary

abandonment of the Montara H1 well.

A departure from PTTEP’s Long Term Suspension policy. At no time (even

after change order regarding Pressure Controlling Corrosion Caps) did the

well design for Well H1 satisfy the requirements for Long Term Suspension as

stipulated in the PTTEP Well Construction Standards. An examination of H1’s

physical status following removal of the trash cap should have led to a

reconsideration of any activity on well H1 until the anomaly had been

considered and risk assessed to ensure personnel and assets were not

placed at risk.

Failures in communication between on and offshore PTTEP personnel in not

identifying the missing 13 3/8” PCCC but it being included on the ‘as built’

information supplied in the Phase 1b Programme and communication

between PTTEP and Seadrill regarding planning changes.

49

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SEA.010.001.0050


Loose application of PTTEP Management of Change policy by circumventing

the formal procedure and using verbal instructions and late follow up of

documentation.

Onboard Supervision that did not recognise the risk associated with over

displacing the 9 5/8” casing shoe or the need for remedial cementing or the

effect this would have on the integrity of the well or how this might impact

PTTEP’s barrier policy.

Onboard supervision that failed to recognise the significance of a missing 13

3/8” PCCC on well H1 at the start of Phase 1B and the agreed removal of the

9 5/8” PCCC leaving at best a single theoretical barrier at the 9 5/8” shoe.

This combination of a failure to follow barrier policy, a failure to follow long

term suspension policy, a relaxed approach to Change Management,

opportunistic program changes, poor communication both on and offshore

and poor onsite decision making culminated in the conditions which led to well

H1 blowing out and the consequences that followed.

50

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Appendix 1 - Incident Photographs

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Appendix 2

Witness Statements - Summaries

Seadrill List of Witnesses

1. Donald Millar – Rig Manager West Atlas 55

2. Phillip Trueman – OIM West Atlas 56 3. Bart Kok - Day Toolpusher 57

4. David Jones - Night Toolpusher 58

5. Iain Stoddart - Maintenance Supervisor 59

6. Michael Glen - Barge Master 60

7. David Horne – Driller 61

8. Dillwyn Davies - Driller / Safety Coach 63

9. Robert Bradford - Assistant Driller 64

10. Luke Taylor - Assistant Driller 66

11. Stuart Louth - Lead Floorman 67

12. Shane Howlett – Floorman 68

13. Didier Lesca - Senior Mechanic 69

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1/13. Donald Millar (Rig Manager):

¤ In Perth at time of incident and contacted at home by OIM (0500hrs Perth

time), advised of burp on well H1

¤ Attended office and contacted again by OIM (approx. 0700hrs Perth time)

and advised second blow-out with uncontrolled discharge – alarms

sounding

¤ Spoke to Craig Duncan (PTTEP Well Construction Manager onsite) and

asked his thoughts – he said “we’re fucked”.

¤ Attended PTTEP Emergency Response Group centre and advised

NOPSA

¤ Rotated at ERG centre with Operations Manager Bruce Worthington

(following arrival)

¤ States unaware of program anomaly re missing 13 3/8” cap

¤ Insisted on program change relative to well GI due to migrating gas, which

was added to Program for Phase 2 of drilling activity (use of diverter)

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2/13. Phillip Trueman (Offshore Installation Manager):

¤ On platform on Thurs 20/08/09 when one of Drlg. Supv’s said they needed

to run brush in H1 to clean threads

¤ On rig floor when supplementary plan brought up to driller about removing

9 5/8” cap and running brush. I looked at plan and said ok – didn’t see any

problem with casing fully cemented

¤ Tested for pressure prior to 9 5/8” cap removed – nil, seawater in 9 5/8”.

¤ In cabin when alarm sounded and went to radio room

¤ Confirmed it was well H1 that blew-out

¤ Contacted the Rig Manager

¤ Well abated and all-clear sounded

¤ Attended Companyman’s office and party to PTTEP notifications and

remedial planning – skid and run RTTS Packer

¤ Crew meeting held and all informed of situation & plan

¤ Went to Cantilever deck and could smell gas, talking on phone to Drlg.

Supv. when it blew the second time

¤ Observed that fluid column was a circumference flow i.e. from annulus

¤ Return to Control Room and Main engines shut down by Maint Supv.

¤ Rig Manager contacted and advised of abandonment plans

¤ Non-essentials given direction to abandon

¤ Situation not getting better and decision made for all remaining personnel

to evacuate

¤ Abandoned on LB#3

¤ Fri 21/08/09 - Problem with cut on H4, incomplete and overpull of maybe

40k used to break it free

¤ Comments – lots of communication when drilling wells during first phase

(Jan – April ’09)

¤ Comment – well GI was actively bubbling when suspended

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3/13. Bart Kok (Day Toolpusher):

¤ On floor when H1 Trash cap pulled off (Thurs 20/08/09)

¤ Advised by Brian Robinson of debris and thread corrosion problems in H1

¤ No 13 3/8” cap fitted

¤ Removal of 9 5/8” cap and ran brush, continued 20” tie-backs / cuts

¤ Insisted on top up of 20” casing with seawater after tie-back (before cut)

¤ In room when first alarm went off (0530hrs Fri 21/08/09)

¤ Attended muster – LB#1 until all-clear sounded

¤ Conducted meeting with PTTEP / OIM, with all crew to explain situation

and remedial plan (skid and run RTTS Packer)

¤ On rig floor and Cantilever deck –attended to lay out of H4 Casing cut-off

and prep for skid

¤ Under rig floor on Cantilever walkways with AD when H1 blew second time

¤ Attended muster and subsequently Coxswain for LB#1

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4/13. David Jones (Night Toolpusher):

¤ Started shift at 1800hrs Thurs 20/08/09

¤ 20” Tie-backs and cuts on GI and H4 overnight

¤ On rig floor when alarms went off, looked over side and saw H1

discharging fluid

¤ Attended muster and then ceased duty when all-clear sounded

¤ Off-duty when second alarm sounded – mustered and abandoned

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5/13. Iain Stoddart (Maintenance Supervisor):

¤ In room when alarm sounded, went straight to Control Room.

¤ Alarms sounding and could not inhibit for announcements

¤ Finally inhibited and then all-clear sounded

¤ Crew meeting and then worked on alarm panel

¤ Second alarm sounded – same problem with alarms and had to repeatedly

reset them to allow announcements and comm.’s

¤ Could see column of liquid through gap under Cantilever from Radio room

plus cloud of vapor

¤ Aware of direction to abandon for non-essential and retention of certain

‘essential’ personnel.

¤ Shut down main engines at shutdown switch panel (lost all phones)

¤ Decision for all essential personnel to abandon and shutdown remaining

services, including emergency generator

¤ Abandoned on LB#3

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6/13. Michael Glen (Barge Master):

¤ In cabin on first alarm sounding

¤ Went to Radio room then to Fire Team muster

¤ Attended Cantilever and inspected site with Brian Robinson – saw gas

vapour rolling up from Mezzanine level

¤ Gas test by Fire team in SCBA (75% LEL), then sample of crude collected

from pool on Helideck

¤ Crew meeting

¤ Assisting in preparing for skidding

¤ Second Blow-out and saw TP and AD come out from beneath rig floor, AD

covered in oil

¤ Attended muster location in Galley – LB#2, further to Boat Station LB#2

¤ Nominated as essential crew and stood out of muster – assisted loading

and launch

¤ Retrieved personal papers from cabin and heard announcement for all

essentials to go to LB#3

¤ Assumed command of LB#2 and launched / evacuated

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7/13. David Horne (Driller):

¤ Thurs 0700 – 1600hrs (short-change day)

¤ H1 trash cap hooked up for removal when I started shift

¤ 1100hr – Brian Robinson (Drlg Supv.) handed me new drillers instructions

for H1 – pull 9 5/8” cap and run brush – first time I heard of it

¤ Remembers Drlg Supv’s O’Shea and Robinson talking about it and saying

“there should be no problems”

¤ Cap pulled while at lunch and after lunch, started running 20” tie-back and

cut about my knock off time (1600hrs)

¤ Started shift at 2400hrs Thurs 20/08/09

¤ Started on 20” tie-back off H4 and continued until cut

¤ Handover to TP Kok at about 0500hrs to have breakfast

¤ 0530hrs – alarm went off and headed back towards Rig Floor to assist

¤ Directed by Brian Robinson to return to Muster – mustered at Galley LB#1

¤ All-clear sounded after about 20mins and went back to Cantilever and kept

crew away from area

¤ Crew meeting – skid and run RTTS Packer plan

¤ Rig Floor, attending to lay out of casing and prep. for skid, walking down

stairs to cantilever when turned and saw full flow coming up out of H1.

¤ Went to end of Cantilever and told Paul O’Shea (Day Drlg Supv) and then

onto Muster in Galley.

¤ LB#2 group getting heated and walked out of muster to Boat station – got

sick of waiting for direction.

¤ Went out to LB#1 Boat Station and re-muster on direction of Control Room

¤ Order to abandon and boarded, launched. Only problem was one hook

didn’t release when on water and had to be done manually.

¤ Comment – regular changes to program during first phase of drilling, most

just to save 2-3mins and cut corners

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¤ Comment – changes made on the fly and no official approvals or

paperwork

¤ Comment – was on rig when H1 was suspended but can’t remember any

specific – nothing about the 13 3/8” cap missing

¤ No Pre-spud when came back on Montara Platform

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8/13. Dillwyn Davies (Safety Coach / Spare Driller):

¤ 2400hrs Wed 19/08/09 – commenced shift

¤ 0900hrs – was at MLS level on platform with Drlg Supv. Brian Robinson at

well H1, safety watch for him as he cleaned threads for tie-back.

¤ Robinson commented “was that a bubble”, referring to something

observed inside the well stump, but no further conversation engaged in

¤ No gas smelt or other unusual activity

¤ 2400hrs Thurs 20/08/09 – commenced shift acting as spare driller / safety

coach

¤ Nothing unusual during night and no smell of gas on platform decks while

working in area

¤ On tender at first alarm and could see under the Cantilever where a clear

flow of oil was flowing straight up to hit underside of rig floor

¤ Stopped people moving towards area and redirected to musters – joined

them (LB#2)

¤ All-clear about 15mins later but restricted to accommodation, and further

all-clear to return to work locations about 30mins after that

¤ In OIM office upon second alarm, straight to muster, directions to Lifeboats

and boarded / abandoned. Took over Coxswain duties as Ch. Mechanic

was pulled out as ‘essential’ crew to stay behind.

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9/13. Robert Bradford (Assistant Driller):

¤ 0700hrs Thurs 20/08/09 – started short change shift

¤ Just pulled H1 Trash cap when came on duty and Brian Robinson (Drlg

Supv) was at MLS deck and said that threads weren’t clean on the 13 3/8”

and we had to clean them

¤ Were set-up to run 20” so laid that out and picked up R/R tool to retrieve 9

5/8” cap

¤ On MLS deck when tool run and J’d into 9 5/8” cap – no pressure obvious.

¤ Attended other jobs after that and then after lunch, ran the 20” casing on

H1 until finished shift

¤ 2400hrs Thurs19/08/09 – commenced shift

¤ Cutting 20” on well GI when commenced work, completed and skidded to

H4

¤ Removed trash cap off H4 and crew ran 20” while I attended to other jobs.

¤ Just after 0500hrs, on rig floor and took over brake from David Horne – 3rd

party had just finished cold-cut but was incomplete.

¤ Drlg Supv. Brian Robinson asked me to ‘flick it’ with link tilt and pull on it –

applied about 5000lbs of Overpull and came free. I don’t how much

Overpull already on string when I took over brake.

¤ Not long after, alarms went off – advised by Brian Robinson that well H1

had just ‘spat’.

¤ Advised OIM and went to Radio room to get gas monitor, returned to site

and stood-by while fire-team made entry to area for tests.

¤ Attended crew meeting and then returned to Cantilever to assist laying out

20” from H4 and skid for RTTS packer on H1

¤ Went under rig floor on Cantilever walkways with Toolpusher (Bart) to

check pistons – in process of checking forward piston when well blew the

second time

¤ I was directly above the well and was enveloped in a column of oil, crawled

out along the walkway and down onto main deck, then to muster (LB#2)

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¤ Removed from boat station muster as part of ‘essential crew’ and went to

Radio room, then briefing room. 5mins later, decision made that all would

abandon and went to LB#3, evacuated rig.

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10/13. Luke Taylor (Assistant Driller):

¤ Was going home Fri morning and last shift was 1200 - 2400hrs Wed

19/08/09

¤ The 9 5/8” cap had just been pulled from H1 at start of my shift

¤ Went to the MLS deck to relieve AD there (Rob Bradford).

¤ Drlg Supv. Brian Robinson was at MLS deck and talking about 13 3/8

threads being dirty. Assisted to stab the brush and stood-by while brush

was worked in 13 3/8”. Remained to help stab in 20” casing and then went

to upper decks

¤ Remaining 20” was run on H1 and then hot cut

¤ Pulled trash cap on GI and started running 20” on it before finished shift at

2400hrs

¤ Woken by alarm at 0530hrs and mustered. Went to boat station and then

asked to remain as ‘essential’ crew so left muster and went to radio room.

¤ Not long after, decision made for all to abandon and went to LB#3 –

abandoned rig

¤ Comment – during first phase of drilling, wells H4 and GI were

communicating

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11/13. Stuart Louth (Lead Floorman):

¤ Worked 1200 -2300hrs Thurs 19/08/09

¤ First job on shift was pulling the 9 5/8” cap – retrieved it but couldn’t get it

off the tool – laid out with it still on the tool

¤ Then went to well GI to run 20” – continued until completed shift

¤ Woken at 0530hrs by alarm – muster at LB#2 muster in Galley until all-

clear, then crew meeting about blow-out

¤ Started shift just before 0700hrs, began by laying out 20” from H4 and

walked down to Cantilever for skidding with Dave (Driller)

¤ Attention called to look under RF and looked to see column of dirty brown

oil with gas that seemed to be evaporating

¤ Driller told me to run and I left the Cantilever deck, onto the main deck and

to muster (alarms ringing by this time)

¤ LB#1 guys seemed to be restless and heated – they left muster before

directions and went out to boat

¤ Musters at Boat Station on directions from Muster Controller and then later

boarded and launched

¤ Comment – thought it was a bad idea to have two muster areas, then

requiring two head counts and delays

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12/13 Shane Howlett (Floorman):

¤ Worked 1200 -2300hrs Thurs 19/08/09

¤ First job on shift was pulling the 9 5/8” cap on H1, retrieved and then ran

brush, also retrieved and laid out

¤ Toolbox and then started running 20” on H1, spent most of shift running

20”

¤ Woken at 0530hrs by alarm – muster at Galley until all-clear, then crew

meeting about blow-out

¤ Started shift just before 0700hrs, began by laying out 3jt’s of 20” from H4

¤ Went down to Cantilever deck to assist in skidding operation

¤ Driller called me and I looked to see solid column of oil coming up through

Helideck hatch of H1. I could heard the loud noise of gas coming up with it

¤ I left the Cantilever deck, onto the main deck and to muster (alarms ringing

by this time)

¤ Mustered in Galley, then directed to boat station muster, then maybe

15mins later, boarded boat (LB#2) and abandoned

¤ Comment – well know during first drilling phase that the wells were

communicating with each other

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13/13. Didier Lesca (Senior Mechanic):

¤ Woke at about 0530hrs and immediately heard alarm – mustered in Galley

for LB#2 and waited for all-clear

¤ Short time later, went to crew meeting where situation explained

¤ Told the mechanic and motorman to stand-by in engine room as I felt this

was not over yet

¤ Doing handover with night mechanic when second alarm sounded,

mustered again and could see through window and under cantilever –

column of oil coming up under rig floor, then dropped off and then surged

back to full stream

¤ Directions given to prepare to abandon – went to boat station and then got

onboard as Coxswain and checked boat, then started to board personnel.

¤ Told I was to stay as ‘essential crew’ and left boat afte

Seadrill – Head Officeunderside of the rig floor and spray outwards. The flow partially subsided...

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