wit.1000.0001 · hold a bachelors degree in mechanical engineering from custin university and a...

OF INQUIRY MONTARA WELL HEAD PLATFORM

UNCONTROLLEDHYDROCARBONRELEASE

COMMONWEALTH OF AUSTRALIA

DECLARATION UNDER THE STATUTORY DECLARATIONS ACT 1959

I, Paul James O'Shea of c/- Level 1, 162 Colin Street, Perth, in the State of Western Australia, Senior

Drilling Supervisor, make the following declaration under the Statutory Declarations Act 1959 (Cth):

Table of topics - Paul O'Shea

l Topic I Paragraphs 1. Current position 1 - 4

2. Qualifications and work experience 5 - 6

3. Montara Development Project I 7 - 9 4. Atlas Drilling 10 - 13

5. My role and responsibilities with the Montara Development Project 14 - 26

6. Communication within PTTEPAA 27-31

7. Communication with Atlas Drilling 32 - 35

Key documents to manage the H1 Well - PTTEPAA

9. Content and knowledge of the key documents 40 - 45

10. Forward plans 46 - 54

11. Changes to the DPs 55 - 58

12. Drilling terminology 5 9

13. 1 Cementing 1 60 - 80

14. Pore pressure & fracture pressure - H1 Well 81 - 84

15. Hydrostatic pressure 85 - 90

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UNCONTROLLED HYDROCARBON RELEASE

16. Drilling, displacement and completion fluids 91 - 103

I I

17. Barriers 104 - 119

18. H1 Well specifics 120 - 125

19. The drilling program for the H1 Well from March 2009 126 - 132

20. Commencing completion 133 - 141

21. 19 August 2009 142 - 144

22. 20 August 2009 145 - 146

23. The 340mm (13 3/s") PCCC 147 - 167

24. 21 August 2009 168 - 178

25. Communications 179 - 185

Current position

1 I am currently contracted through Labrador Petro Management (Labrador) to Vermilion Oil & Gas

as a Senior Drilling Engineer/Supervisor .

2 My usual occupation is Senior Drilling Supervisor or Senior Drilling Engineer.

3 I provide my services through a company called PJ Drilling Consultants Pty Ltd and am engaged as a

consultant by Labrador. I have been contracting to Labrador for approximately 5 years.

4 Labrador contracted my services to PTTEP Australasia (Ashmore Cartier) Pty Limited (PTTEPAA)

between about November 2007 and Februa~y 2010.

Qualifications and work experience

5 I have extensive experience in the oil and gas industly. I hold a Bachelors Degree in Mechanical

Engineering from Custin University and a Masters Degree in Petroleum Engineering from the

University of New South Wales.

6 My work experience is as follows:

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O F INQUIRY MONTARA WELL HEAD PLATFORM


(a) from November 2007 to February 20 10 - Senior Drilling Supervisor for PTTEPAA on the

West Atlas;

(b) from Februaly 2006 to November 2007 - Senior Drilling Engineer for Apache Energy Ltd;

(c) fsom January 2005 to February 2006 - Drilling Engineer for Labrador; and

(d) from 1997 and December 2004 - Senior Logging While Drilling Engineer for Sperry-

Sun/Hallibui-ton.

The Montara Development Project

7 PTTEPAA is developing the Montara, Skua, Swift/Swallow Fields in the East Timor Sea. The

development of these fields is referred to as the Montara Development Project and is located about

690 km west of Darwin, Northern Territoiy, near the Ashmore Cartier reef.

8 The Montara Development Project involves four production wells including the H1-ST1 well (H1

Well) and a gas injection well, in the Montara Field, two production wells in the Skua Field and three

production wells in the Swift/Swallow Field.

9 The Montara Development facilities include a wellhead platform (WHP) at the Montara Field.

Atlas Drilling

10 Atlas Drilling (S) Pte Ltd (Atlas Drilling) was contracted by PTTEPAA for the Montara Drilling

campaign, including the construction of the H1 Well, at the Montara WHP.

l l Atlas Drilling owns the West Atlas jack-up drilling rig (West Atlas), which is a type of Mobile

Offshore Drilling Unit (or MODU)

12 Most of the personnel on board (POB) the West Atlas were employed by Atlas Drilling and they

reported to Atlas Drilling's Offshore Installation Manager (who at all times relevant to this statement

was Phillip Trueman) (OIM). Directly under the OIM were:

(a) two Tool Pushers each working 12 hour shifts: one from 0600 hours to 1800 hours and the

other from l SO0 hours to 0600 hours;

(b) two Drillers each working 12 hour shifts: one fiorn 1200 hours to 0000 hours and the othes

from 0000 hours to 1200 hours;

(c) a Safety Officer working between 0600 hours and 1800 hours;

10263986-1

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(d) a Barge Master working between 0600 hours and 1800 hours; and

(e) two Crane Operators each working 12 hour shifts: one from 1200 hours to 0000 hours and

the other from 0000 hours to 1200 hours.

13 The Atlas Drilling personnel would work outside of these times whenever required and were always

willing to offer advice and guidance to complete the job safely and efficiently.

My role and responsibilities with the Montara Development Project

14 I commenced working as a consultant to PTTEPAA in November 2007. For the first 2 months I

worked at PTTEPAA's West Perth office as an Engineer (including a 10 days shift offshore on the

MODU called "The Wilcraft") before commencing the role of Senior Drilling Supervisor on the West

Atlas.

15 When I was in the PTTEPAA office I reposted to PTTEPAA's Well Construction Manager, Craig

Duncan.

16 When I was on the West Atlas I reported to either Mr Duncan or PTTEPAA's Drilling

Superintendent, Chris Wilson (depending who was on duty).

17 Operations on the West Atlas continued 24 hours a day.

18 I was on duty between 0600 hours and 1800 hours as the Day Senior Drilling Supervisor and worked

outside these hours as required. I worked a 3 week cycle alternating with Noel Treasure, another

Senior Drilling Supervisor contracted to PTTEPAA. I was onboard the West Atlas fsom 5 February

2009 to 25 February 2009,26 March 2009 to 16 April 2009 and 6 August 2009 to 21 August 2009.

19 The PTTEPAA Night Drilling Supervisors on the West Atlas were Lindsay Wishai? and Craig

Klumpp.

20 As the Senior Drilling Supervisor on the West Atlas, my responsibilities included:

(a) supesvising and monitoring construction of the Montara wells by Atlas Drilling;

(b) organising and overseeing all well construction operations on the West Atlas;

(c) ensuring the well construction work was carried out by Atlas Drilling personnel and

PTTEPAA contractors in accordance with approved PTTEPAA programs, policies and

procedures on well construction and safety;

f4

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(d) liaising with the OIM and developing forward plans as to what we wanted to do on a

particular day or operation; and

(e) reporting to PTTEPAA personnel in Perth (Chris Wilson and Craig Duncan).

Well construction operations were the activities carried out to achieve the drilling and completion of

the Montara wells. These activities included the activities described in the Drilling Programs (which

I describe below).

The well construction operations were only part of the activities on board the West Atlas. The OIM

also had responsibility for all of those other activities, which are referred to as "rig management".

These include staffing issues for the Atlas Drilling POB and management of rig maintenance.

The POB who reported to me with regard to well construction operations were:

(a) PTTEPAA's Night Drilling Supervisor (who was Lindsay Wishart at all times relevant to

this statement);

(b) third parties engaged to provide services on the West Atlas, including, relevantly,

Halliburton who were engaged to conduct the cementing; and

(c) Mathieu Higgins and Steven Loveless - PTTEPAA's Drilling EngineersILogistics.

I would liaise with Atlas Drilling's personnel on the West Atlas, including the OIM, Tool Pushers,

Drillers, Assistant Drillers, Barge Master and Crane Operators on the implementation of the well

construction operations. All of these people were available to me as sources of information.

As Senior Drilling Supervisor I was in charge of issuing forward plans for well construction

operations (which I describe below). The Tool Pushers would ensure PTTEPAA forward plans were

carried out, would continually report activities/progress/issues to the OIM and would provide me

with direct information whenever I required it. The Barge Master was in charge of the West Atlas

deck management.

The OIM was ultimately in charge of the West Atlas.

Communication within PTTEPAA

27 There were three main forms of communication within the well construction team. They were email,

telephone and face to face meetings:

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(a) email communications were common:

( 9 the main email of significance was the provision of daily reports from the West

Atlas. This email included the Daily Drilling Report (DDR), mud reports, bulk

reports and the daily POB list. It also included a description of what was going on

by way of background to the day's activities. The DDR and email were generated

by the PTTEPAA Night Drilling Supervisor (relevantly, Mr Wishai-t) and checked

by the PTTEPAA Senior Drilling Supervisor (either Mr Treasure or me, depending

on who was on duty at the time) on the majority of occasions;

(ii) another important email was the 7 day look ahead which was generated on the West

Atlas by the PTTEPAA Drilling Engineers in consultation with the PTTEPAA

Senior Drilling Supervisor. This spreadsheet outlined the next seven days plans for

well construction, personnel movements and vessel/helicopter movements;

(iii) these emails went to a number of people within the well construction team. The

person responsible for day to day operations (Craig Duncan or Chris Wilson) would

also generate a morning update email intended to give a one page summary of what

had happened the day before and what was planned. This was distributed widely to

PTTEPAA, Atlas Drilling and third party contractors;

(b) telephone calls were less formal:

( 9 there was a scheduled morning call between the West Atlas and the person

responsible for day to day operations, (Craig Duncan or Chris Wilson) at about

0900 hours CST. This call was a review of events and future plans and normally

took about 15-30 minutes;

(ii) normally there was an afternoon or evening call from the West Atlas to Craig

Duncan or Chris Wilson;

(iii) calls to and from the West Atlm were made at required times depending on

operations and could be made by either of the PTTEPAA Drilling Supervisors.

Many days involved multiple telephone calls and also conference calls involving

multiple persons depending on the issues at hand; and

(c) a contractors9 meeting was held on the West Atlas eveiy morning at 0700 hours CST

(Contractors' Meeting):

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(i) the OIM, Atlas Drilling's Safety Officer and senior personnel and PTTEPAA third

party contractors attended the Contractors' Meetings; and

(ii) the Contractors' Meetings normally took between 20-30 minutes and were an

opportunity to brain storm problems and ensure that all relevant personnel were

aligned for the day's work and upcoming operations.

If situations occurred that required another opinion, I would contact either Mr Wilson or Mr Duncan

in Perth. Mr Wilson and Mr Duncan were also rostered on call outside of work hours so that one of

them could be contacted at any time.

If there was an issue that could not be sorted out on the West Atlas, we would ask Mr Duncan or Mr

Wilson to sort it out with Atlas Drilling management.

I had a good relationship with Mr Duncan and Mr Wilson. I would talk with them at the scheduled

morning and afternoon telephone call, and at other times if necessary, to discuss operational issues

and just to keep them informed of what was happening on the West Atlas.

Mr Wilson would often be on call for two or three weeks in a month and then Mr Duncan would take

the on call duties for a week to 10 days. I would initially report to whoever was on call and then

sometimes we would have conference calls between Mr Duncan, Mr Wilson and myself.

Communication with Atlas Drilling

Phillip Trueman was the OIM on the West Atlas between 19 and 2 1 August 2009

I had a good relationship with Mr Trueman. Mr Trueman attended the Contractors' Meetings

including those held on 19 and 20 August 2009 and we discussed events that occurred the previous

day and what was scheduled for that day to make sure that everyone was prepared. Both online and

offline tasks were discussed during the Contractors' Meetings and directly with Mr Trueman.

Mr Trueman and I had an open door policy. That is, we would not always schedule times to meet,

but, when I needed to, I provided him with copies of relevant documents and discussed what we

wanted to achieve that day and he would give me his thoughts.

The Tool Pushers did not attend the Contractors' Meetings, however, I had discussions during the

day with the Tool Pushers about well construction operations, both online and offline activities. I

had a very close relationship with the Tool Pushers.

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Key documents to manage the Well - PTTEPAA

The key PTTEPAA documents in construction of the Montara wells including the H1 Well were:

the Well Construction Standards (WCS) (ie Well Construction Standards - D41-502433

Rev 2; 13 March 2009);

the Construct, Service or Abandon Well Process standard or manual (Process Manual) (ie

Construct, Sewice or Abandon Well Process Management Standard - D41-502434 Rev 2;

13 March 2009). The WCS and the Process Manual are parts of PTTEPAA9s Well

Construction Management System (WCMS);

the Basis Of Well Design (BOWD) (ie Montara Development Basis of Well Design - Montara H1 - TM-CR-GEN-E-150-00008 Rev 0; July 2008);

the Drilling Program @P) (ie. Montara GI, H1 & H4 (Batch Drilled) Drilling Program -

TM-CR-MON-B- 150-0000 1; Rev: 2; 6 January 2009);

the Drilling and Completion Program @P 1B) (i.e. Montara Phase 1B Drilling and

Completion Program - TM-CR-MON-B- 150-00003 Rev: 0; 30 June 2009); and

forward plans (Instruction To Drillers).

I was aware of the existence of the West Atlas Safety Case (including revisions) and that the OIM

would refer to those documents to ensure that the well construction operations complied with the

West Atlas Safety Case.

Because the OIM was ultimately in charge of the West Atlas, it was his responsibility to ensure that

all well construction operations complied with the West Atlas Safety Case.

If there was any conflict between well construction operations and the West Atlas Safety Case that

conflict had to be resolved during discussion between the OIM and me and, if necessary, between Mr

Duncan or Mr Wilson and the West Atlas rig manager (Donald Millar). This was a process of

discussing and agreeing appropriate changes to the fonvard plans to make them consistent with the

DP, DP 1B and the West Atlas Safety Case.

Content and knowledge of the key documents

40 The Process Manual was generally not applicable to the offshore well construction operations.

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Well Construction Standard

41 I applied the WCS to the drilling and construction of the Montara wells.

42 I had a good knowledge of the contents of the WCS. I would refer to the WCS as required and had a

hard copy in my office on the West Atlas.

43 The WCS was a relevant document in my role as a PTTEPAA Senior Drilling Supervisor as it

described the standards which were set by PTTEPAA and which we were required to operate to. It

included specific information in relation to the construction of the wells, including cementing and

barriers.

Drilling Programs

44 The DP and DP 1B (collectively the DPs) were issued from the PTTEPAA Head Office in Perth. The

DPs were the most important documents for the offshore operation. I would generally sign a

transmittal document to say that I had received the DPs and email the transmittal document back to

Perth. If a copy had not already been given to them, I would give the DPs to the other relevant

contractors or third party personnel, the OIM and the Tool Pushers.

45 The DPs contained the procedure for how the wells were to be drilled and the activities to occur on

the West Atlas. All the well designs were incorporated into the DPs. The DPs also contained details

of the equipment to be used and the casing strings. All the engineering design of the wells was done

in Perth.

Forward plans

46 From the DPs I developed forward plans (the WCMS refers to these plans as Instructions To

Drillers) which specified the operational sequence of the required work. These were prepared for

each phase of the well construction operations and would cover periods of differing duration

depending upon the phase and the work required to complete that phase. The forward plans were

updated as necessary as events changed.

47 The forward plans contained sequential practical instructions on the well construction operations.

The plans were a more detailed practical expansion of the operational aspects of the DPs, that is they

provided details about how the DPs were to be implemented. The forward plans might, for example,

include details about casing assemblies, nozzle and drill bit types and drilling rig operations that were

to be used during the particular phase of the well construction operations.

WIT.1000.0001.0134



I would generally prepare a draft forward plan the day prior to the planned commencement of an

operation or phase.

I would usually give a copy of the draft forward plan to the:

PTTEPAA Night Drilling Supervisor and get him to check it over and make sure that what

was contained in the forward plan was in accordance with what we were supposed to be

doing as set out in the DPs;

PTTEPAA Logistics/Drilling Engineer if he was on shift and for his comments;

OIM for comment and review. He would review the forward plan to ensure it complied

with the West Atlas Safety Case and provide comment on whether the practical steps could

be undertaken in a more efficient way. In effect in seeking the OIM's input I was asking

him three questions: Is the forward plan practical and efficient (is it OK)? Is there a better

way of doing what is planned? Will the OIM implement it, ie will the OIM allow the rig and

the rig personnel to implement the forward plan as proposed?

Tool Pushers for comment and review. They would provide comment on whether the

practical steps could be undertaken in a more efficient way. I was in effect asking the Tool

Pushers the first two questions asked of the OIM as I have set them out above; and

cementing hand if the draft forward plan involved cementing, and to the casing hand if the

forward plan involved running casing. They would provide comment on whether the

practical steps could be undestaken in a more efficient way. Again, I was in effect asking the

cementing hand whether the forward plan was practical and efficient and if they had any

suggestions about a better way of doing what was planned.

The drafts of the folward plan would either be returned to me without change and usually with the

person returning that copy of the draft writing " O K on the returned copy. If someone had any

suggestions to make about the draft forward plan, those suggestions were discussed (sometimes with

more than one person, depending on the nature of the suggestion) and, if the OIM and I agreed that

some change was appropriate, I would revise the draft forward plan.

Once any agreed amendments had been made, I produced the final revision of the forward plan and

distributed it. I would hang copies on my office door on the West Atlas, give a copy to the Tool

Pusher, Driller and Assistant Driller on the West Atlas rig floor and distribute a copy to all the third

party contractors.

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If the forward plan dealt with matters that were not within the combined expertise of the POB, or if I

wanted input from anyone onshore, I would send a draft of the fonvard plan to PTTEPAA's onshore

office via email for comment and review by Mr Wilson or Mr Duncan and it would be specifically

discussed with them before being issued. If I wanted input from onshore staff I would initiate any

follow up by telephone. For more "standard" operations, the folward plan was discussed with Mr

Wilson or Mr Duncan over the telephone, usually during the scheduled 0900 hours CST morning

telephone call.

If a change to the operation proposed in the forward plan was required after the folward plan had

been issued (usually as a result of some change that happened in the course of the forward plan being

implemented), I would issue:

(a) a revision of the forward plan to incorporate that change. A revision of the forward plan

would supersede the originally issued forward plan; or

(b) a supplementary forward plan. A supplementasy forward plan would be read in conjunction

with the originally issued forward plan.

I would hang a copy of any revised or supplementary forward plan on my office door on the West

Atlas, deliver a copy to the West Atlas rig floor and distribute a copy to any third pasty personnel who

were involved in the operation covered in the forward plan.

Cha~~ges to the DPs

The DPs could be changed via a change control process, described in Section 9 of the Process

Manual.

We differentiated between a change of significance and a change of insignificance. A change of

significance would be something like moving a casing shoe or doing something which was a material

change to the DPs. A change of insignificance one might be a typo, or a change in the sequence of

the DPs operations.

I also regarded the DPs to carty within them a "fit for purpose" requirement for each stage. That

meant that if something had to be done to make sure that casing was fit for purpose that had to be

carried out and did not require any change in the DPs before it was done. Examples of this include

ensuring that all casing and tie backs were clean and free of corrosion.

If I identified a significant issue that required a change to the DPs, I would contact Mr Wilson or Mr

Duncan and discuss the change. If they agreed, a Change Control Request Form would be prepared P A

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by either Mr Wilson or Mr Duncan, approved by Mr Duncan, and then distributed to the people to

whom the DPs had been originally issued.

Drilling terminology

59 Various equipment and processes were involved in drilling the Montara wells, including:

(a) the WHP which comprises two main parts. The Jacket is the lattice structure connected to

the seabed. The Topsides Module - which includes controls, process equipment and a

helicopter deck - is attached to the Jacket;

(b) the West Atlas, the MODU;

(c) casing, including:

(i) 508mm (20") diameter casing;

(ii) 340mm (13 3/8") diameter casing; and

(iii) 244mm (9 5/<) diameter casing;

(d) drill strings, which are called Bottom Hole Assemblies (BHAs) and which are the

configuration of downhole drilling tools used to drill hole sections;

(e) the annulus, which is the fluidtspace between two casings or a casing and the hole;

(f) float shoe, which is the first part of a casing string run in hole and represents the deepest part

of the casing string. A float shoe contains a one way device which is designed to allow

cement to flow through it in a downwards manner but not come back up;

(g) shoe track is the internal part of the float shoe between a float collar and the one way device

located at the deepest part of the casing. The shoe track consists of 1 to 3 joints of casing;

(h) float collar, which is a one way valve to allow fluid to pass through it from above and

prevent fluid coming back up through it. A float collar is fixed on to the inside of the

casing. A float collar is made of concrete with a drillable metal device inside, which means

that it can be drilled out with a drill bit;

(i) cemented float shoe, cemented shoe casing or cemented shoe track, describes the situation

where cement has been pumped below a float collar into the float shoe to form a barrier at

the deepest point of the well. The cemented float shoe is cemented casing;

P4

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an auto fill float collar assembly has a bar holding the valve open when it is being run in the

hole. This allows the fluid in the hole to travel up into the casing. The drilling fluid is able

to flow back up through the valve and self-fill the casing;

PCCCs or pressure containing corrosion caps;

blow-out preventers (BOPs) which are a series of hydraulically controlled Rams that can be

used to stop fluid coming up the annulus;

wellheads, which are pressure containing devices that connect casing strings to each other

and to BOPs. For the Montara WKP these are surface wellheads;

Mud or drilling fluid, which is the fluid in the hole. It provides a primaly source of well

control during drilling operations. It is used to hold the open hole section open (ie prevent

collapse) and is used to remove cuttings during drilling operations;

Mud Line Suspension (MLS), which involves setting the weight above neutsal pointltop of

cement from a casing string to the outer casing stsing, ultimately supported by the 508mm

conductor casing;

Retrievable Test Treat and Squeeze (RTTS) packers, which can be used to seal the inner

portion of a casing string or hang off drill pipe during a cyclone evacuation;

cement plug, which is a barrier created by an amount of cement being pumped into the

casing leaving drilling fluid or displacement fluids above and below the cement;

Top Plug and Bottom Plug, which are pre fabricated plugs that are used when cement is

being pumped into the casing to form a cement barrier such as a cemented float shoe or a

cement plug. Bottom Plugs used with the Montara wells had a "rupture disc" in the centre

to allow the flow path to open. The Bottom Plug would be released ahead of the cement and

the Top Plug would be released on top of the cement. The Top Plug forms a solid layer

between the cement column and the displacement fluids;

batch drilling and sequential drilling - the drilling of a well can be broken down into a series

of tasks or operations performed in sequence. This is sometimes described as the drilling

sequence of operations. There are certain points in the sequence where it is practical to

interrupt the sequence of operations. For example, once a certain casing stsing has been set

and cemented, it is practical to interrupt the sequence. Batch drilling is where a number of

wells are drilled and the sequence of operations on one well is interrupted, allowing work Pn

to

13 eo

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be undestaken on the same sequence of operations on a different well. Batch drilling has

some benefits including optimal use of drilling fluids and equipment supply. It also has a

disadvantage in that interrupting the sequence of operations on one well comes at a time cos

for the rig to be moved from one well to the next. It is generally accepted that the

advantages of batch drilling outweigh the disadvantages and batch drilling is preferred to

sequential drilling; and

(t) "online" work is that past of the well constructions operations that are undestaken while the

drilling rig (in this case the West Atlas) is over the relevant well. "Offline" work is that part

of the well construction operations that are undestaken while the drilling rig is positioned

over some other well.

Cementing

Planning

The planning for the cementing of the wells was done in Perth in accordance with the WCMS. The

actual implementation was done on the West Atlas in accordance with the DPs.

One of the things that I did on the West Atlas in relation to the cementing operation was calculate the

volumes of cement and displacement fluids. I would initially calculate by hand the volumes requised

and then verify these calculations by inputting the necessary data into the "Casing Cementing Calcs"

spreadsheet which would automatically calculate cement and displacement volumes based on that

data.

I would also ask the PTTEPAA Night Drilling Supervisor andtor the LogisticstDrilling Engineer and

the Hallibuston cementer to verify the cement and displacement fluid calculations.

While it was a collaborative process to determine the cement and displacement fluids calculations,

my figures were used for the cementing operation.

I would prepare the forward plan for cementing operations. The forward plan outlined whether the

West Atlas or Hallibuston would perform the displacement of the cement and the displacement fluid

to be used.

However, I did not prepare the calculations for the cementing of the casing in the H1 Well that took

place on 7 March 2009.

t

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Valve failure

The cement for the cementing of the shoe float is pumped into place under pressure. The pressure

will increase after the cement has reached the casing shoe (or the Top Plug and the Bottom Plug have

come together and "bumped" at the float collar).

At this point the casing is pressure tested by maintaining that pressure on the column of displacement

fluids.

The WCS says that this pressure should be held for 20 minutes. The previous standards under the

Petroleum (Submerged Lands) Act required 10 minutes of held pressure.

It is possible that the valves in the shoe casing can be damaged or blocked open during the pumping

of the cement into the shoe casing. If that were to occur, it would be possible for cement or other

fluids or gases to return back up through the shoe track. The cement could retum through the

damaged or blocked valve under its hydrostatic pressure and force the Top Plug and possibly the

Bottom Plug back up the casing from its previous position (on top of or somewhere above the float

collar). This sometimes happens although it is not a regular occurrence.

If that were to occur, you would probably get backflow at the surface and you would know that the

valve in the float shoe (and float collar) had failed.

If there is a failure in the valve (or valves) you need to hold the cement static and wait for it to set.

After the cement sets you would then release the pressure to ensure there was no backflow and then

reapply pressure to the casing to perform a casing pressure test.

If you bled off much more than the volume of fluid that was required to reach the necessary pressure

to make the Top and Bottom Plugs "bump" or deliver the cement into place below the float collar,

this may suggest a valve failure.

It would be usual to stop bleeding off when you have bled off the amount of fluid that was required

to reach the necessary pressure. When the well is horizontal, there is an increased risk of a channel

along the topside (highside) of the cement if you get flow back which enables the cement to come

back through the shoe track and into the casing. This is because the cement is heavy and wants to sit

on the low side of the well.

In order to minimise the risk associated with cementing horizontal wells, large volumes of cement are

pumped into the well. The casings also have centralisers, which are designed to hold the casing in

the centre of the hole and maximise the chances of getting cement all the way round the casing. f n

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Cementing contractor reports

Hallibui-ton was the cementing contractor for the Montara Development Project and performed the

cementing ofthe shoe float on the H1 Well.

The usual reporting process is that Halliburton would either, on the day of or in the morning of the

day following the cementing work, give to the on board Senior Drilling Supervisor, a cementing log,

the pressure graphs, a chemical usage form and a performance review (or client satisfaction) form.

If these were given to me I would check them, fill out the client satisfaction form and return that form

to Halliburton and then email the other documents to the PTTEPAA onshore office. I did not give

any of these documents to the OIM or any other Atlas Drilling personnel.

Hand over

I was not onboard the West Atlas during the cementing of the 244mm (9 '18") float shoe casing on the

H1 Well. I was not aware of any problem with the cementing until after the Uncontrolled Release on

2 1 August 2009.

Noel Treasure had been the onboard Senior Drilling Supervisor between 25 February 2009 and 26

March 2009. When I returned to the West Atlas on 26 March 2009, I had a discussion with Mr

Treasure about what had happened while I was onshore. This was a normal hand over discussion.

There was no mention about any problems with the cementing of the float shoe or of any valve

failures.

I saw the Hallibui-ton documentation for the cementing work for 7 March 2009 for the first time after

21 August 2009.

Pore pressure & fracture pressure - H1 Well

8 1 The pore pressure of the H1 Well was listed in the BOWD as Normal - 1 .O4sg.

82 This figure was provided by the Montara Project geologist David Thornton. To me, the word

"normal" was of more importance than the numerical pressure value.

83 "Normal pressure" is equivalent to that of seawater which is usually considered to be 1 .O3sg. When

the field discovery wells were evaluated, the reservoir pressures were resolved to be slightly less than

sea water.

WIT.1000.0001.0141



84 The fracture pressure in the H1 Well was listed in the BOWD as being 1.40sg near the reservoir. This

is the fluid density which at reservoir depth could result in fracture break down of the formations.

This figure was an estimate.

Hydrostatic pressure

Hydrostatic pressure is the pressure exerted by a fluid at rest. In the context of well construction, it is

the pressure exei-ted by the fluid in the well at a particular vertical depth in that well.

The pressure can be calculated as the vertical depth * the fluid density * gravity. At any point in the

well, gravity and vertical depth can be considered constant. As density is the only variable it is

common to refer to the reservoir pressure in a well in terms of density.

This allows easy comparisons between resesvoir or formation pressures and mud densities.

If the mud hydrostatic pressure is greater than the formation pressure, the mud within the well is said

to be "over balanced" to formation.

If the formation pressure is greater that the hydrostatic pressure due to the mud then the mud within

the well is said to be "under balanced".

An unrestrained, and under balanced situation leads to an influx of formation fluids into the well.

Drilling, displacement and completion fluids

Typically there are three main types of fluids used in drilling: drilling fluids, displacement fluids and

completion fluids.

Most drilling operations use Mud to transport rock fragments from the well, cool the drill bit and to

provide hydraulic pressure to suppoi-t the hole being drilled.

Often, the Mud is comprised of water and various chemicals which help to stabilise the rock

formations being drilled. The fluid properties of the Mud are engineered specifically for a pasticular

hole section and are often adjusted during the drilling process to respond to wellbore conditions.

The completion fluid might come into contact with the producing formations so it is kept clean to

reduce the risk of contaminating the reservoir. Much of the completion fluid will not contact the

resesvoir formations and has corrosion inhibitors added to slow degradation of the well casing and

completion components.

Two types of completion fluids are brine and seawater.

WIT.1000.0001.0142



The difference between brine and seawater is that brine is salty water and the salt may or may not be

sodium chloride. Typically sea water is about 35,000 parts per million of chloride and the weight is

about 1.03 sg.

Section 6.6 of the W C S states that:

6.6 Primary Well Control

Formation Integrity Tests or Leak off Tests shall be carried out below each pressure containment casing shoe on all wells.

For development wells the FITILOT may be omitted on the production casing string.

Kick tolerance shall be calculated for all pressure-containment casings using the following parameters:

Maximum anticipated reservoir pressure Gas gradient of 0.23 SG (0.1 psilft) unless the actual is known 700 kPa (1 00 psi) surface handling safety margin

The following kick tolerance limits shall be applied:

Condition Minimal Acceptable Kick Tolerance

For wells in which the reservoir pressure is known and the mud hydrostatic 0.75m3 (5 bbls) pressure exceeds this known pressure then the most likely cause of a well control incident is swabbing

For wells in which the reservoir pressure is uncertain 3. 18m3 (20 bbls)

While drilling, a detailed ongoing assessment of the actual kick tolerance shall be conducted. Drilling must not continue with a kick tolerance below the levels stipulated in the Drilling Programme (and as defined above).

The mud loggers should continuously monitor pore pressure indicators during drilling operations and repoi-t increasing trends. On critical wells an on-site pore pressure prediction contractor should be considered.

The following minimum stock levels shall be maintained onboard during exploration or appraisal drilling:

0 Enough cement and additives to set a 150m (500 ft) plug in open hole 406mm (16")or smaller. o Enough weighting materials and additives to raise the active mud system by 0.12 SG (1.0 ppg)

Primary well control shall be cassied out in accordance with the Registered Operator Well Control Manual. Any additional procedures and deviation shall be specified in the Vessel Safety Case Revision.

Primary well control shall be maintained at all times during conventional drilling operations. The programmed mud gradient shall exceed the highest pore pressure gradient of the exposed permeable formations with a minimum static overbalance of 1,000 kPa. (143 psi )

When the pressure margins between pore pressure and fracture gradient are narrow, the ECD shall be calculated continuously.

During exploration drilling, to detect the transition from normally pressured formations to abnormally high pressured formations, the following characteristics of the formation lithology and the formation fluid content shall be continuously monitored:

WIT.1000.0001.0143



Gas levels in the drilling fluid return e The shape of shale cuttings in returns o FEWD log response o The change in temperature and salinity of the drilling fluid return o Indications of bore hole instability or torque and drag

Flow checks shall be performed in the following circumstances using the Registered Operator's procedures unless othelwise specified in the Safety Case Revision. In addition to the requirements of the Vessel Safety Case the following must be flow checked:

o Any indications of downhole gains or losses e Immediately a known hydrocarbon bearing objective is penetrated e Prior to POH, prior to pumping a slug, at the last casing shoe, just prior to pulling the BHA and if trip

displacement is incorrect e Drilling breaks in the reservoir section exceeding 1.5m (5 ft) in length e Prior to dropping a survey or dropping a core ball

The Drilling Supervisor shall include any special or additional requirements for flow checks in the Instructions to Drillers.

If the fluid volume to fill the hole is not correct, a further flow check shall be performed and the bit shall be returned to the bottom and bottoms up circulated before continuing.

The trip tank shall be used while tripping.

However, in a cased hole, nothing is "exposed".

Section l I o f the WCS states that:

The density of any completion fluid, workover fluid or packer fluid must be designed to balance formation

pressure at the top perforation plus, as a minimum, 1000Kpa (143psi)

Section 5 WCS (set out in full below) refers to "fluids" being overbalanced to formation.

Displacement fluids are used in the cementing, do not typically come in contact with open hole and

can be a mixture of seawater and corrosion inhibiters.

The WCS does not expressly deal with the characteristics of any displacement fluids.

Section 2.3.1 o f the Seadrill Well Control Manual states, without defining "drilling fluids", that "all

drilling fluids be of sufficient density to contain formation pressure". This requires all "drilling

fluids" to be overbalanced to formation pressure.

Barriers

104 Section 2 o f the WCS defines "barriers" to mean "any means of preventing an uncontrolled release or

flow of well bore fluids to surface".

WIT.1000.0001.0144



105 Section 5 of the WCS states:

During drilling, completion, testing, intervention and other open hole operations the following barriers shall be maintained in the annulus:

0 Two proven barriers between hydrocarbon bearing permeable zones and the surface One proven barrier between permeable fresh water bearing zones and surface

Barriers during Completion, Testing , Intervention and Other Open Hole Operations

Barrier Type Description

0 Each annular or ram BOP 0 Wellbore fluid stable at surface, provided it can be monitored

Proven 0 Wireline set plugs in the tubing that have been pressure tested

RTTS type packer that has been pressure tested Master valve Lubricator

Temporary suspension is where the MODU or well intervention vessel remains on location. The following minimum number of tested, independent barriers shall be installed on annulus and tubinglcasing above the highest open hydrocarbon zone or over-pressured water zone:

1- I Heavy Lifting

Move Rig Over Well Drilling/Completion/Testing or Intervention Heavy Weather Operations

Remove/Install BOPIXmas Tree

1 permanent and 1 permanent or 2 temporaly l temporaty 2 temporary

Barriers during Temporary Suspension

Barrier Type Description

Cement Plug Permanent 0 Permanent Packer with no controlled internal flow path

Cemented Casing

BOP closed and locked on drill pipe or tubing 0 Retrievable Packers

Wireline Plugs Temporary 0 Fluid with a hydrostatic head greater than formation pressure, provided that the liquid level and

density can be monitored and maintained. 0 Closed SSSV that has been tested

A single temporary barrier may be used for temporary suspension, provided that petrophysical logs and other data confirm beyond doubt that no hydrocarbon zones or over-pressured water zones are present in either the wellbore or annuli.

For long terms suspension and abandonment requirement refer to Section 14.

Barriers must be verified in-situ as follows:

Barrier Type Verification

Tagging with sufficient force to confirm the top of good cement Cement Plug Tagging pressure must equal the equivalent of 3500KPa (500 psi) Not surface plugs

Or Pressure testing to 7000 KPa (1000PSI) over leak off Cement plug on bridge Tag bridge plug then pressure testing to 7000 KPa (1000PSI) over leak off after setting

Lplug I cement plug

WIT.1000.0001.0145



a Waiting until the surface cement (tail) samples are set, providing that the cement job proceeded normally and a clear pressure differential was observed prior to bumping the

Annulus Cement plug a The differential pressure must confirm that the TOC is a minimum of 50m above any

hydrocarbon or over-pressured water zone All Other Barriers By either pressure or inflow testing

"Open hole " operations involve drilling beyond some existing casing so that there is some uncased

hole exposed.

Sections 14.1 and 14.2 of the WCS relevantly state:

14.1 Long Term Suspension

Long Term Suspension is when the MODU leaves the well site. Wells must be suspended so that they can be abandoned with rig less intervention to meet the standards below.

Two permanent tested barriers must be installed in the annulus and well bore above any hydrocarbon zone or over pressured zone. The following are permanent basriers:

Barrier T y p e Description I

Permanent Pressure tested cement Plug (min 30m in length) Permanent Packer with no controlled internal flow path and cement on top Cemented Casing with proven TOC Hanger Packer

I Tubing Seals Annular Master Valve

14.2 Abandonment

Two Dermanent tested barriers must be installed in the annulus and well bore above any hydrocarbon zone or over pressured zone. Abandonment Programmes must comply with the following:

Section Requirement

Open hole Cement plugs shall be placed with a minimum of 30m of cement above and a minimum of 30m below any significant oil, gas or fresh water zones

Casing a Where there is open hole below the casing shoe a cement plug shall be placed extending a minimum of 30mabove and 30m below the casing shoe,

or A cement retainer with effective back pressure control shall be set >10m and <30m above the casing shoe with a cement plug calculated to extend at >30m below and >15m above the retainer. Where lost circulation conditions exist a permanent type bridge plug should be set <45m above the shoe with >15m of cement on top.

a Intervals of cased hole between cement plugs shall be filled with fluid suitably inhibited to prevent the corrosion of casing string.

Potentially All must be cemented off. productive zone behind casing

Casing Stub A cement plug shall be placed to extend >10m above >40m below the stub. A retainer may be inside Casing used in setting the required plug.

WIT.1000.0001.0146

COMMISSION OF INQUIRY MONTARA WELL HEAD PLATFORM


Requirement

Perforations A cement plug shall be spotted and extend from at least from 30m below to at least 30m above the top perforated interval

or r A cement retainer set in the casing not more than 45m above the top of the perforated interval with a

cement plug extending at least 15m above the retainer provided the perforated interval is isolated from open hole below or subject to the above if a succession of retainers are used to isolate a series of perforated intervals.

r The topmost retainer requires a minimum of 15m of cement placed above it. This plug must be tagged or pressure tested to a minimum of 3500KPa (500psi) above the leak-off or estimated fracture gradient at the point of injection.

Liners D A cement plug shall be placed immediately above each liner hanger to extend >30m above the hanger. This plug must be tagged or pressure tested to 3500KPa (500psi) above the leak off or estimated fracture gradient at the point of injection.

Surface All casing strings on wells to be abandoned shall be severed below the seabed. A surface cement plug >45m in length shall be placed in the innermost casing string extending tc the seabed with the top of the plug <45m below the seabed. No annular space which extends to the seabed shall be left open to drilled hole below the annulat space.

For offshore wells, a seabed survey and subsequent cleanup by ROV shall be conducted and noted in the IADC Drilling Report. A video shall be made and sent to the Drilling Superintendent.

A well abandonment schematic shall be prepared at the wellsite and sent to the Drilling Superintendent for fmal drafting together with full details of the components. The schematic shall include all relevant dimensions and equipment serial numbers to ensure traceability.

A corrosion cap should be installed on the MLS.

A trash cap should be installed on the conductor or the subsea wellhead.

Neither section 5 nor section 14 of the WCS expressly mention PCCCs but, instead, refer to 2

different types of functionally similar casing seals. These are RTTS type packers (section 5 ) and

tubing seals (section 14).

These seals like PCCCs are also manufactured devices machined to withstand manufacturer's

specified amounts of pressure and designed to be inserted into and removed fsom wells as required.

RTTS packers work by essentially squeezing an elastima element against the inside of the casing to

form a seal.

The tubing seals are 0 rings fitted to a tubing hanger to form a seal within a machined surface in a

well head.

A PCCC uses 0 rings to form a seal within a machined surface within a MLS hanger.

WIT.1000.0001.0147



The tubing hanger has a flow path through the middle which must be plugged to form a seal.

Typically the plug is a tubing hanger plug (very similar in design to a PCCC) and screwed into place

within the flow path of the tubing hanger.

The RTTS packer and the PCCC both have mechanical valves that allow for pressure testing or fluid

to be pumped below the barrier and serve to form a seal that can be removed as required.

The PCCC is at surface and threaded onto the MLS hanger and the RTTS packer is designed for use

at points deeper into the well. The PCCC also protects the threads required for tie back from

corrosion that might occur through exposure to the elements.

Each of a RTTS packer, tubing hanger and PCCC are designed to allow the pressure beneath them to

be checked and released while they are in place.

Each of a RTTS packer, tubing hanger and PCCC are designed so that they can be installed through a

BOP.

The WCS lists possible barriers by their functional characteristics. Accordingly, references to tubing

hanger and RTTS packer in the WCS are essentially interchangeable and are synonyms for PCCCs in

the context of a choice as a barrier.

I understood that if the West Atlas was over the WHP, the wells were temporarily suspended and that

if the West Atlas moved away from the WHP, there was a long-term suspension.

H1 Well specifics

Overview of Drilling Programs - original plan and revisions

120 The original plan for the Montara Field Development was to have the WHP Topside in position and

for the West Atlas to be positioned adjacent to the completed WHP to drill and complete the wells by

batch drilling.

121 This plan was unable to be executed due to issues with the contracted construction vessels which

resulted in the WHP Topside not being installed as originally planned.

122 This resulted in the DPs being revised to incorporate two phases.

123 The first phase was to drill and suspend the wells at the 244mm (9 5 / 8 " ) casing point prior to the WHP

Topside installation; the second phase was the continuation of drilling and completion of the wells

after installation of the WHP Topside.

fd

WIT.1000.0001.0148



The DP was initially revised in November 2008 to incorporate the fact that the WHP Topside would

not be in place and the wells sequentially drilled down to the 244mm (9 5/s") casing shoe and

suspended. The DP was again revised in January 2009 to reflect that the wells were to be batch

drilled down to the 244mm (9 5/8") casing shoe and suspended.

The DP 1B addressed the completion of the wells after the suspension (incorporating the drilling of

the reservoir section of the horizontal wells and the running of the sand exclusion screens) and was

issued with "As Built" information after the wells had been suspended.

The drilling program for the H1 Well from March 2009

There were a variety of procedures used to suspend the Montara wells.

Originally, the suspension method for the Montara wells included:

(a) backing out each casing at the MLS; and

(b) installing a cement plug from l6Om to 1 15m.

The suspension process was done both online and offline.

A third PTTEPAA Drilling Supervisor, Brian Robinson, was on the West Atlas in March and April

2009 to assist with the offline work. I discussed with Mr Robinson what was scheduled each day and

how it was going to be done. This was to ensure that what Mr Robinson was doing was not going to

clash with online activities on the West Atlas rig floor.

I am aware that a Well Construction Management of Change was approved in early March 2009 to

change the method of suspension of the H1 Well. I have been shown Well Construction Change

Control Form Number D65005A 006, dated 12 March 2009, and this shows that the revised

suspension method consisted of:

(a) cemented casing;

(b) a column of inhibited sea water;

(c) 340mm (13 3/8") and 244mm (9 '/X") MLS PCCCs; and

(d) a 508mm (20") trash cap.

WIT.1000.0001.0149



I was not involved in implementing this change to the suspension of the H1 Well. The 244mm (9

5/8") PCCC was installed and documented while I was not on the West Atlas.

In my view, the H1 Well was suspended in accordance with the DPs and the WCS, as it had a

cemented shoe track, PCCCs and inhibited fluid in the well. The cemented casing and PCCCs were

permanent barriers and the inhibited fluid was also a barrier.

Commencing completion

When we returned to re-enter the H1 Well on 19 August 2009, I had not seen the reference in the DP

1B that, during cementing of the 244mm (9 5/8") casing, the floats had failed.

After initial preparations for work, the initial work scope was to re-establish the top 20 meters of the

casing and MLS back to where the well head was going to be. This involves a tie back of casing

strings.

Next, the BOPs were to be nippled up again and pressure tested. Then the BHA was to go in and the

shoe track and plugs drilled out, followed by the horizontal open hole section.

During the tie back we had to tie back 3 casing strings. Firstly we had to tie back the 508mm (20")

conductor. The conductor was strong enough to support the weight of all the loads including the

BOPs which were about 90 tons. With the 508mm (20") conductor installed, we would cut that

accurately to height and then install the first wellhead section. The first wellhead section elevation

would dictate the stack up height for all the other casings.

The plan was to take off the trash cap, nipple up the 508mm (20") conductor with a PCCC on the

340mm (13~1~") casing and a PCCC on the 244mm (95/s") casing.

Sections 5.6, 5.16 and 5.17 of DP 1B covers these steps as follows:

5.6 Tie-back 508mm (20") casing - Montara H1 ST-1

15) Remove the trash cap from the well using a tugger

Check the threads on the 508mm (20") conductor

16) Rig-up to run 508mm (20") conductor

17) Make-up the landing string (Figure 28) and run in the hole

18) Carefully make-up the Leopard connection on the MLS and engage the anti-rotation tabs

19) Rough cut the casing above the mezzanine deck and recover the landing string.

Pn

WIT.1000.0001.0150



20) Skid to well slot 13-WD-009 (Montara GI)

21) Offline cut the 508mm (20") casing at 4.661m above the platform main deck (Figure 28) with a cold cutter and recover the cut-off.

22) Offline install the Braden Head and orient per Appendix 5 (Due North or parallel to the aft of the rig pointing starboard). Record wellhead serial number on the DDR

23) Offline install Aker debris cover P/N 585776-P5

5.16 Tie-back 340mm (13 318") casing - Montara H1 ST-1

173) Run in the hole with the corrosion cap sunning tool.

174) Make up the TDS before engaging the sunning tool onto the corrosion cap (this will allow for any pressure below the corrosion cap to be observed on the standpipe and then bled-off through the choke manifold)

175) Engage the corrosion cap and check for any pressure below the corrosion cap. Note any pressure on the IADC and the DDR. Bleed-off any pressure via the choke manifold.

176) Remove the corrosion cap by rotating clockwise for 8-9 turns with a torque of 2034 - 4745Nm (1 500-3500 ftlbs) and recover same to surface.

177) Rig-up to run 340mm (1 3 318") casing

178) Make-up the MLS tieback tool to the landing string.

Confirm all seals are intact

Lubricate seals with Jet Lube AP-5 or equivalent. DO NOT use pipe dope or lubricant containing metal particles.

179) Run in the hole with the MLS tieback tool and space-out to ensure that no casing couplings are in the vicinity of the surface wellhead

180) Lower the tieback tool onto the MLS and apply 0.9 to 2.2MT weight down and mark the pipe at the rotary table

181) Rotate the string to the right 9.5 to 10.5 turns maintaining constant weight down on the string with a torque of 3390 to 5424Nm (2500 - 4000 ftlbs). The string should have moved 89mm down.

182) Hydrotest the tieback by filling the casing with water.

183) Install the casing slips (Aker P/N W85859-133EA-2W). The slips are fully installed when the distance from the top of the slips to the top of the starter head is 216mm (8.52")

184) Install the cold cutter and cut the 340mm (13 318") casing 127mm (5") [+l- 3mm (0.12")] above the top surface of the starter head ensuring the outer edge has a bevel per Aker Procedures 6 1-PH2059-70 (M176).

185) Once the casing is cut recover the landing string to surface.

186) Change from casing elevators to drillpipe elevators and make-up the pack-off running tool complete with the pack-off (P/N W85860-133A-2Q).

WIT.1000.0001.0151



187) Whilst rigging-up to run the pack-off clean out the cavity above the slips in the starter head in preparation to run the pack-off.

188) Install the pack-off per Aker Procedures 61-PH2059-70 (M176).

189) Pressure test the pack-off to 10.9MPa (1 584 psi) - 70% of the collapse pressure of the casing for 10 minutes

190) Once successfully pressure tested engage the pack-off

19 1) Recover the pack-off running tool

192) Change out the 340mm (13 318") pack-off running tool for the 244mm (9 518") pack-off running tool.

5.17 Tie-back 244mm (9 518") casing - Montara H1 ST-1

193) Run in the hole with the corrosion cap running tool.

194) Make up the TDS before engaging the running tool onto the corrosion cap (this will allow for any pressure below the corrosion cap to be observed on the standpipe and then bled-off through the choke manifold)

195) Engage the corrosion cap and check for any pressure below the corrosion cap. Note any pressure on the IADC and the DDR. Bleed-off any pressure via the choke manifold.

196) Remove the corrosion cap by rotating clockwise for 8-9 turns with a torque of 2034 - 4745Nm (1 500-3500 ftlbs) and recover same to surface.

197) Rig-up to run 244mm (9 518") casing

198) Make-up the MLS tieback tool to the landing string.

Confirm all seals are intact

0 Lubricate seals with Jet Lube AP-5 or equivalent. DO NOT use pipe dope or lubricant containing metal particles.

199) Run in the hole with the MLS tieback tool and space-out to ensure that no casing couplings are in the vicinity of the surface wellhead

o Install a 340mm X 244mm (13 318" X 9 518") casing centralizer below the surface wellhead as the 244mm casing will be cut without the casing slips in place.

200) Lower the tieback tool onto the MLS and apply 0.9 to 2.2MT weight down and mark the pipe at the rotary table

201) Rotate the string to the right 9.5 to 10.5 turns maintaining constant weight down on the string with a torque of 3390 to 5424Nm (2500 - 4000 ftlbs). The string should have moved 89mm down.

202) Hydrotest the tieback by filling the casing with water.

203) Install a water head bushing on the casing complete with a side entry sub and a TIW.

204) Pressure test the casing to 27.5MPa (4000psi) for 20 minutes to check the integrity of the MLS connection. P n

WIT.1000.0001.0152



NOTE: This will pressure test the entire 244mm (9 518") casing string.

205) Nipple-down from the casing pressure test

206) Install the cold cutter and cut the 244mm (9 518") casing 509mm (20.04") [+l- 3mm (0.12")] above the top surface of the starter head ensuring the outer edge has a bevel per Aker Procedures 6 1-PH2059-70 (M176).

207) Recover the landing string

208) Change from casing elevators to drillpipe elevators (whilst installing the wellhead)

209) Install the unitized Aker Wellhead per the Aker procedure 61-PH2059-70 (M176). Orient the wellhead per the wellhead orientation procedure (Appendix 5)

210) Pressure test the neck seals against the 340mm (13 318") casing to 10.9MPa (1584 psi) - 70% of the collapse pressure of the casing for 10 minutes.

21 1) Pressure test the cavity between the starter head and the unitized wellhead to 10.9MPa (1584 psi) - 70% of the collapse pressure of the casing for 5 minutes.

212) Install the 244mm (9 518") slip landing guide (Figure 30)

e The slip landing guide will consist of a cut-off joint of 244mm (9 518") casing with 3 guides welded to the inside base. The guide will be lowered through the unitized wellhead and mate-up with the already cut 244mm (9 518") casing. The slip landing guide will allow the slips to be wrapped around the casing and lowered into the wellhead without snagging-up on the already cut casing.

213) Install the casing slips (Aker PIN W85716-095A-3W). The slips are fully installed when the distance from the top of the slips to the top of the unitized wellhead is 703mm (27.66")

214) Once the slips are installed remove the slip landing guide.

215) Make-up the pack-off running tool to drillpipe (a minimum of 3T weight is needed to set the pack-off)

2 16) Install the pack-off per Aker Procedures 6 1-PH2059-70 (M 176).

217) Pressure test the pack-off to 22.96MPa (3330 psi) [70% of the collapse rating of the casing] for 10 minutes

2 18) Once successfully pressure tested engage the pack-off

219) Take 4.5T overpull to c o n f m that the pack-off is engaged.

220) Recover the pack-off running tool

22 1) Skid to slot 13-WD-001 (Montara H4)

222) OFFLINE: Install the tree Jig (Figure 31) to allow construction to take measurements for the flow lines. Once measurements have been taken nipple down the jig

223) OFFLINE: Remove one manual 52mm (2 1116") side outlet valve and replace with two hydraulic actuated 52mm (2 1/16") side outlet valves for the 244mm (9 518") annulus gas injection manifold tie in. Confirm with Production/Construction crew on correct side of

WIT.1000.0001.0153



unitized wellhead for the Gas Injection manifold tie in as well as hydraulic actuator orientation for hydraulic control line tie in.

224) OFFLINE: Install the 4.5m high pressure riser using a double drive lock adaptor to the unitized wellhead (Figure 32).

225) OFFLINE: Install the drive-lock adaptor (loose) and cross-over spool onto the riser in preparation for the BOP's. When the rig is tying back the last well (H3) the BOP's should be able to skidded towards the H1 well and made-up to the drive-lock assembly

Section 5.17 of the DP 1B shows that the 244mm (9 5/8") casing would be exposed to atmosphere

when the 244mm (9 5/8") PCCC was removed.

As the DP planned a batch drilling program the 244mm (9 5/8") casing would be exposed to

atmosphere while the 244mm (9 'l8") PCCCs were removed from the remaining wells. This could

take 24 hours or so.

This exposure to atmosphere is consistent with convention on surface wellhead type operations,

where allowances are made for BOP removal after cement has set as contemplated in the Seadrill

Well Control Manual and commonly practised within the industry.

19 August 2009

142 On 19 August 2009, I prepared forward plan # lb that detailed the steps to be taken to tie back the

508mm (20") conductors on all the Montara wells. This was finalised in the usual way that I have

described above.

143 The well construction operations set out in that forward plan were effectively a situation where the

West Atlas would move over the H1 Well. As a result I considered that the requirements for

temporary suspension in section 5 of the WCS applied, being either 1 permanent or 2 temporary

barriers to be in place and for those barriers to have been tested in situ by either pressure or inflow

testing.

144 As at 19 August 2009, I thought there was a competent cemented shoe float, overbalanced

displacement fluid in the H1 Well (I knew that the reservoir was slightly under "normal") and a

244mm (9 78") and a 340mm (13 3/8") PCCC in place in the H1 Well. Therefore, there were 4

barriers in place in the H1 Well.

20 August 2009

145 I got up around 0500 hours and caught up on the morning reports and had a discussion with Mr

Wishart. I had a conversation with Mr Wishart, Mr Robinson and Mr Higgins about what we were

In

WIT.1000.0001.0154



going to do during the day and forward planned. We were all happy with what we were going to do

and work started on the H1 Well in accordance with forward plan #lb.

146 Mr Robinson removed the 508mm (20") trash cap from the H1 Well offline.

The 340mm (13 3/s") PCCC

When the 508mm (20") trash cap was taken off, Mr Robinson telephoned me and told me that there

was a bit of corrosion on the threads of the 340mm (13 3/8") casing. So I went down onto the MLS

deck level of the WHP to have a look at the corrosion. The 340mm (13 3/8") PCCC had obviously

not been installed as reported to me in April 2009.

Mr Robinson and I then spoke with Mr Duncan on the helideck of the WHP about the corrosion.

The thread was going to be important for the casing to be tied back and the casing was going to be

required over a 15 to 20 year period for the well so it was desirable to clean the 340mm (13 3/g")

casing threads now rather than risk the corrosion worsening in the future and compromising the

integrity of the casing. The 340mm (13 3/8") casing thread had to be fit for its purpose of sealing the

casing and that would not be the case if it was corroded.

Mr Robinson, Mr Duncan and I agreed that:

(a) we would need to lun the BA51L brush tool into the 340mm (13 3/8") casing to clean the

corrosion off the threads. The brush tool uses brushes similar to street sweeping blushes;

(b) in order to get the brush tool in to clean the 340mm (13 3/8'7) threads it would be necessary to

remove the 244mm (9 PCCC.

It was desirable to clean the 340mm (13 3/8") threads at this stage to enable a visual inspection of

them. Once the 508mm (20") conductor was installed a visual inspection was impossible. So there

was a need to delay the installation to the 508mm (20") conductor.

I then went up to the West Atlas rig floor where Atlas Drilling personnel were rigging up to run the

508mm (20") tie back conductor. I spoke to Mr Trueman and the Driller on shift about the corrosion

in the 340mm (13 3/s") casing threads and the requirement to clean the threads, which would involve

the removal of the 244mm (9 '/g") PCCC. I told Mr Trueman and the Driller that I would prepare a

supplementary forward plan to cover this operation.

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I went into my office and prepared the supplementary fonvard plan. As I prepared the supplementary

forward plan I telephoned Mr Wilson, who was in Perth, and discussed the issue with him and let him

know that we had discussed it with Mr Duncan. Mr Wilson agreed with this course of action.

I did not consider that removing the 244mm (9 '/gn) PCCC at this stage would cause any issue with

regards to barriers. With the West Atlas at the WHP we would operate under the Temporary

Suspension requirements of the WCS. The H1 Well had been suspended some 5 months or so earlier

and upon removal of the 244mm (9 'ls") PCCC there was no reason to believe the H1 Well was not

static and that it would remain in that state while the 244mm (9 '18") PCCC was off.

I did not need to request a formal change to the DP 1B for cleaning the 340mm (13 3/g") casing

threads because that task did not impact on the integrity of the H1 Well. The West Atlas was at the

WHP and even without the 244mm (9 5/s") PCCC the H1 Well was suspended by 1 permanent

barrier, the cemented casing, and l temporary barrier being the over balanced suspension fluids.

There was a slight change in the sequence of the well construction operations but, again, for the

reasons I have just mentioned, I did not consider that required any formal change to the DP 1B to be

requested.

I provided the supplementary forward plan to Mr Trueman, Tool Pusher (MS Kok) and Driller and

Atlas Drilling personnel. No concerns about the supplementary forward plan operation were raised

by Atlas Drilling personnel during the execution of that operation.

The preparation for the removal of the 244mm (9 5/~") PCCC was carried out over a 3-4 hour period.

Before we removed the 244mm (9 'ls") PCCC, I obtained confirmation from Mr Kok that we would

be able to monitor pressure through the drill pipe that would be attached to the suspended H1 Well

via the corrosion cap running tool.

We then ran the corrosion cap running tool in to remove the 244mm (9 'l8") PCCC. The corrosion

cap running tool had a pin that stabs into the poppet in the 244mm (9 '/S") PCCC to allow a check for

trapped pressure below. The Driller, Tool Pusher and I did not see any pressure at surface on the

gauges which are on the rig floor.

The 244mm (9 '/gV) PCCC was turned a couple of turns (2-3) to see if any pressure would escape

through the threads between the 244mm (9 '18") casing and the PCCC. I was on the West Atlas rig

floor for this entire operation and in communication with Mr Robinson, who was at the MLS deck

level, via hand held radio. I could not see the MLS deck level from the rig level. I confirmed with

C A

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Mr Robinson that he saw nothing coming from the edge ofthe 244mm (9 5/8") PCCC and confirmed

the well was static.

The 244mm (9 5/s") PCCC was then backed all the way out and pulled up to the rig floor. I again

confirmed with Mr Robinson, via radio, that the H1 Well was static and there was no flow.

Mr Robinson placed a gas meter at the top of the 244mm (9 '/g") casing and confirmed to me that

there was no gas detected.

I remained on the rig floor and Mr Robinson remained at the MLS deck level. Atlas Drilling

personnel then performed the cleaning of the 340mm (13 3/g") threads. At no stage did I receive any

reports from Mr Robinson or the Atlas Drilling personnel of gas bubbles or fluid flow.

When the cleaning of the 340mm (13 3/8") threads was completed, Mr Robinson told me that the

threads were now in good condition. The Atlas Drilling personnel pulled the brush tool back out and

ran the 508mm (20") casing. The casing was then filled with seawater up to 1 metre below the

proposed cut level of the 508mm (20") casing. Then the 508mm (20") casing was cut and the cut

joints were laid down. The West Atlas rig floorlcantilever then moved on to the next well (G1 ST-1).

There were no signs or reports of the H1 Well being unstable through out this process.

I handed over to Mr Wishart at 1800 hours. I probably went to bed at about 2300 hours at which

time there were no signs or reports of the H1 Well being unstable.

21 August 2009

168 I got up just after 0500 hours. The West Atlas alarm went off around 0530 hours. When the alarm

went off I went up to the radiolcontrol room on the West Atlas. There was a bit of confusion as to

why the alarms were going off and then the radio operator received a report from Mr Robinson on the

WHP that one of the wells had kicked, ie discharged 40-50bbls of fluid. Initially, it was not clear

which well had kicked because we were skidded across to the H4 well at the time. Initially, it was

assumed in the control room that it was actually the H4 well.

169 I contacted Mr Duncan because he had gone to the lifeboats which was his muster point. I asked him

to come up to the radio room to discuss what had happened. I discussed the matter with Mr Duncan.

We could not understand why the H4 well had kicked as we had not actually removed any PCCCs

from the H4 well.

170 Mr Duncan went downstairs into the PTTEPAA office to try and determine what had happened.

( A

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About 5 minutes later I spoke via radio to Mr Robinson who was at the WHP. He told me that it was

actually the H1 Well that had unloaded 40-50bbls. I went down to talk to Mr Duncan about it and let

him know that it was actually the HI Well that had unloaded. We telephoned Mr Wilson in the

process to let him know what was going on.

I then set about taking steps to respond to the Uncontrolled Release.

Non essential personnel on the West Atlas were then evacuated using lifeboats Nos 1 and 2.

The position worsened and the OIM decided that all remaining POB should evacuate.

All remaining POB evacuated to lifeboat No. 3. I was in lifeboat No. 3.

We experienced a problem when being lowered as the lines stalled, but this was quickly resolved by

barge master and we safely evacuated.

I was very impressed with the evacuation which ran smoothly.

All POB seemed to know and follow the evacuation procedures and I am aware of the safety drills

that had be done on board, including an induction by Atlas Drilling's safety officer, frequent

evacuation drills involved mustering personnel at the lifeboat stations (including some occasions

when personnel got in to a lifeboat without the lifeboat being lowered) and regular maintenance

carried out by Atlas Drilling personnel of the lifeboats, including lowering boats and driving them

around. I do not recall seeing lifeboat No. 3 being lowered in any drill or maintenance.

Communications

179 I have been asked by the Commissioner to provide my response to certain questions and, to the extent

that I have not already addressed them, I provide the following additional responses.

180 I do not believe at any stage that there was a break down or lack of communications between

PTTEPAA and Atlas Drilling offshore on the West Atlas. The level of communication and co-

operation on board was vely good. I had an excellent relationship and a vely open line of

communication with the Atlas Drilling personnel.

181 Based on the fact that I now know that the 340mm (13 3/8") PCCC was not installed as had been

recorded in the DDRs, I do, however, believe some oversight was made which led to the 340mm (13

3/8") PCCC being left off.

182 Despite attempts to find out how that might have come about, I do not know how that happened. h'

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I do not believe at any stage there was a break down or lack of communications between PTTEPAA

and Halliburton personnel offshore on the West Atlas. I had an excellent relationship and a vely open

line of communication with the Halliburton personnel. The Halliburton reports were provided.

I do not believe that there was a lack of communication between parties on the West Atlas. It is

possible, after reconsidering everything that has occurred, that some further information about the

cementing of the shoe casing could usefully have been exchanged when I did my handover with Mr

Treasure on 26 March 2009, but nothing that occurred then caused the Uncontrolled Release.

Perhaps too, with the benefit of hindsight, I could have reviewed the Halliburton cementing reports

when I returned to the West Atlas on 26 March 2009, but there was no need for me to do that at that

time and not reviewing them so far after the cementing took place could not have caused the

Uncontrolled Release.

I understand that a person who intentionally makes a false statement in a statutory declaration is guilty of an

offence under section 11 of the Statutory Declarations Act 1959 (Cth), and I believe that the statements in

this declaration are true in evely particular.

Paul James O'Shea

Declared at Perth the 8th day of March 20 10

declaration is made

LT ' M L L F _ ( ~ - f i f l i ' K f i d i ~ ~ f lu. f14.rl F!;!&% $alif!icati6;,"and :&ress of person before whom the declaraeon is rna e

WIT.1000.0001.0159

wit.1000.0001 · hold a bachelors degree in mechanical engineering from custin university and a...

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