FINAL REPORT OF

THE FINDINGS OF THE INVESTIGATION INTO THE PIPE RUPTURE AND FIRE INCIDENT ON 3 JUNE 2008 AT THE FACILITIES OPERATED BY APACHE ENERGY LTD ON

VARANUS ISLAND

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REVISION STATUS Rev Date Description Author Reviewed by

Z Lambert Investigation

Team S. Sherman

Member A Draft

Investigation

B Richardson Team

Investigation Member

Team Member

Z Lambert B 11/09/08 Draft G. Guyan

. Richardson

Z Lambert C 12/09/08 Final S Schubach

B Richardson

Z Lambert G. Guyan

C1 07/10108 Final B Richardson

S Schubach

DISTRIBUTION

Position Company

1 Records management NOPSA - original and controlled

2 Director of Petroleum and

Dol R - uncontrolled copy Royalties Division

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1. EXECUTIVE SUMMARY

Varanus Island is situated approximately 100 km west of Karratha. Located on the island are oil and gas production facilities operated by Apache Energy Ltd. A number of facilities are located offshore in the waters surrounding Varanus Island and are connected by subsea pipelines to the production facilities on Varanus Island. Collectively, this complex is operated by Apache Energy Ltd, such that hydrocarbons are fed to the Varanus Island facilities and processed prior to export either via two sales gas pipelines to the mainland, or via a crude oil export line to transit tanker vessels.

On the afternoon of the 3 June 2008, at approximately 13:30, a series of explosions followed by fires occurred at the Apache operated facility on Varanus Island.

At the time of the event, there were 150 personnel at the Apache facility on Varanus Island and a further 16 on adjacent offshore platforms.

There were no reported injuries or fatalities as a result of the explosions and fires.

The explosions and fires were concentrated in an area adjacent to the Harriet Joint Venture (HJV) gas plant, on the NNE beach pipeline corridor, where 6 pipelines in close proximity to each other cross the beach.

The plant was shutdown, isolated and vented. All personnel at the Apache Varanus Island onshore facility were mustered and accounted for. By the evening of 3 June 2008 all personnel were evacuated except a skeleton crew of 14 persons who stayed on the island for monitoring purposes.

The fires were extinguished in the early hours of the 5 June 2008.

Apache oil and gas production related activities on the island are regulated under the Western Australian Petroleum Pipelines Act 1969 (PPA69), which is administered by the Western Australian Department of Industry and Resources (WA DoIR). The WA DolR initiated an investigation into the events of the 3 June 2008. The National Offshore Petroleum Safety Authority (NOPSA) was requested by the DolR to assist in the conduct of its investigation of the incident and documented terms of reference for the investigation were prepared.

The investigation found that:

1. The activities on the island prior to the incident can be described as routine. The Apache production plant was being operated as normal, with only routine work being carried out. Some project construction work was being undertaken within the plant area. There is no evidence that this project work activity had any impact on, or contributed to the incident.

2. There was no evidence of any contemporaneous extrinsic activity contributing to the cause of the incident.

3. Evidence indicates that the immediate cause of the incident was the rupture of the 12" sales gas pipeline at the NNE beach crossing and that the gas released from the ruptured pipeline ignited very soon after the rupture.

4. Evidence to date indicates that the pipe was being operated at a pressure within its design envelope. The rupture occurred due to thinning of the pipe

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wall due to corrosion of the external surface of the pipe resulting in excessive stresses in the pipe wall.

Evidence indicates that as a consequence of the initial 12" sales gas pipeline rupture and ignition of the gas released, the adjacent Campbell / Sinbad to Varanus Island 12" infield gas pipeline also ruptured and released gas which contributed to the fire . As a result of direct or radiant heat impact from the initial ruptures and fires on the beach, the 16" sales gas pipeline and the 6" Harriet Gas Line also ruptured at the boundary of the HJV plant. In addition, part of the HJV plant was damaged.

Evidence gathered to date indicates that the main causal factors in the incident were:

1. Ineffective anti-corrosion coating at the beach crossing section of the 12" sales gas pipeline, due to damage and/or dis-bondment from the pipeline.

2. Ineffective cathodic protection of the wet-dry transition zone of the beach crossing section of the 12" sales gas pipeline on Varanus Island.

3. Ineffective inspection and monitoring by Apache of the beach crossing and shallow water section of the 12" sales gas pipeline on Varanus Island.

There are aspects of some lines of investigation that have not been settled, principally due to delays by Apache in providing information and delays in forensic testing of pipe samples. In particular:

• Completion and full analysis of the forensic testing of pipe samples; • Statements from key Apache personnel (Apache on behalf of its key

personnel declined requests for interview); • Identification of specific technical details relating to the cathodic

protection of the 12" sales gas pipeline.

These matters may be resolved in due course. However, such resolution is unlikely to significantly change the nature of the findings of the investigation and hence this Report is considered to adequately address the terms of reference ·of the investigation. It is understood that DolR will review this Report with a view to considering further action.

The investigation identified that Apache Northwest Pty Ltd and its co-licensees may have committed offences under:

1. Petroleum Pipelines Act 1969, Sections 36A & 38(b) 2. Petroleum Pipelines Regulations 1970, Regulation 10.

Some findings of the investigation may also constitute non-compliance with pipeline licence conditions .

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2. TABLE OF CONTENTS

1. Executive Summary

2. Table of contents

3. Abbreviations

4. Introduction

5. Background

5.1 Location

5.2 Applicable Legislation , Codes and Standards

6. Investigation Activities

6.1 Activities at the Apache Operated Facilities on Varanus

Island

6.2 Activities Subsequent to Site Visit of Apache Facilities on

Varanus Island

6.3 Impediments to the Investigation

7. Findings

7.1 Environmental Conditions

7.2 Sequence of Events

7.2.1 Events Leading up to the Incident

7.2.2 Sequence of Incident Events

7.3 Potential for Injury

7.4 Incident Location and Layout

7.5 The Incident

7.6 Post Incident Events

7.7 Damage

7.8 Failure Mechanism of the 12" sales gas pipeline at Varanus

Island NNE Beach Crossing

7.9 Pipelines IMMR (Inspection , Maintenance and Monitoring

Regime)

7.9 .1 Resources and Organisation

7.9.2 Apache's Use of Contractors

7.9.3 Apache12" sales gas pipeline IMMR

7.1012" Sales gas pipeline C P System design

8. Conclusions

8.1 Immediate Cause of the Incident

8.2 Main Causal Factors

8.3 Other Factors

9. Possible Breaches of Legislation

10. Attachments

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3. ABBREVIATIONS

AEL Apache Energy Ltd ALERT Organisation contracted to AEL to

investigate the incident on their behalf CP Cathodic protection CS1 Compressor station 1 located on the

mainland DBNGP Dampier to Bunbury Natural Gas

Pipeline DolR The Western Australian Department

of Industry and Resources ERT Emergency response team ESD Emergency Shut Down ESJV East Spar Joint Venture GGT Goldfields Gas Transmission HAT High Astrological Tide HJV Harriet Joint Venture IMMR Inspection Maintenance and

Monitoring Regime LAT Low Astrological Tide m metre mm millimetre NNE North-North East NOPSA National Offshore Petroleum Safety

Authority OHS Occupational health and safety' P&ID Process and Instrumentation Diagram PL Pipeline Licence PMP Pipeline Management Plan POB Persons on board PPA69 Petroleum Pipelines Act 1969 (WA) PRO Petroleum and Royalties Division of

DolR P(SL)A82 Petroleum Submerged Lands Act

1982 (WA) PSMP Pipeline Safety Management Plan PTW Permit to Work ROV Remotely Operated Vehicle SDV Shutdown valve WST Western standard time

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4. INTRODUCTION

DolR requested NOPSA to provide investigation services under the WA DoiR's direction, in order to investigate a pipe rupture and fire that occurred on 3 June 2008 at the Varanus Island gas processing plant operated by Apache Energy Limited.

The request was made in accordance with the Service Contract in place between NOPSA and the State of WA through the Department of Industry and Resources dated June 2007.

The investigation team comprising a DolR inspector and two NOPSA inspectors travelled to Varanus Island on 4 June 2008. Upon arrival on the island at 17:30 the investigation team was unable to proceed directly to the incident site as Apache advised that it would be unsafe to do so since small fires were still burning. Apache also advised that it was anticipated that, by the following morning of 5 June 2008, the fires would be extinguished and it would be safe to access the incident site.

The investigation team gained access to the incident site on the 5 June 2008, and commenced the investigation. The investigation team left Varanus Island on 7 June 2008.

The investigation was conducted as per the terms of reference agreed between DolR and NOPSA (see Attachment 1 for details).

The investigation and its attendant findings were delayed by difficulties experienced in sourcing information and accessing personnel. These matters are further discussed in section 6.3.

In accordance with the terms of reference, the focus of the investigation was to identify:

. • Facts and events relevant to the incident • The likely causes of the incident • Any actions and omissions by the operator of the Varanus Island facility, or its

contractors, leading up to the Incident and during the Incident that may have contributed to the cause of the Incident

• Any potential for injury to persons arising directly from the fire and explosion(s) at the time of the incident

The terms of reference for the investigation did not include:

• assessment of the extent of the damage to the plant, except where directly relevant to the main focus of the investigation

• events that occurred after the incident, except where they were directly relevant to the main focus of the investigation

• actions or omissions by any regulator, in particular the DoIR, regarding assessment of the appropriateness of the DolR consents and approvals issued to the pipeline licensee with respect to the Varanus Island plant and associated licensed pipelines.

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5. BACKGROUND

5.1 Location

The incident occurred at the Apache facilities on Varanus Island which is part of the Lowendal group of islands located to the east of the northern end of Barrow Island (approximately 100 km west of Karratha) .

• West Try al Rocks

- "__ i 11 'I­i

ftibr!99,i -

VARAN US PRODUCTION

• AREA (V)

12" & 16" Sales gas pipelines

DBNG pipeline

Compressor Station No 1

GGT pipeline

Map 1 - Location of Apache Varamis Island Facilities

Apache Energy Ltd operates oil and gas production facilities on and around Varanus Island. Hydrocarbons are piped to the island for processing . After processing, the hydrocarbon products are exported as either gas to the mainland via two subsea pipelines (12" and 16" sales gas pipelines, approximately 100 km long), or as crude oil by tankers from the terminal at the island .

Apache's gas production from its facilities on Varanus Island accounts for approximately 30% of WA gas consumption .

5.2 Applicable Legislation, Codes and Standards

The WA Petroleum Pipeline Act 1969 (PPA69).

This Act regulates the processing and conveyance of petroleum within WA and is applicable to the Apache Varanus Island plant. Pipeline licences were issued by DolR under this Act to Apache and its co-venturers for the oil and gas production facilities on the island. The relevant licences are:

• PL 12 and variations, for the Harriet Joint Venture facilities and associated pipelines onshore Varanus Island including the 12" sales gas pipeline.

• PL 29, PL30 for the East Spar Joint Venture facilities and associated pipelines onshore Varanus Island

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Pipeline licence PL 12, held jointly by Apache Northwest Pty Ltd and two other entities, covers the area of the Varanus Island facility affected by the incident. Licence PL 12 was granted in May 1985 with 21 years vailidity. An application for renewal of the licence was submitted to DolR by Apache in December 2005 and has not yet been accepted. In the interim, the PPA69 stipulates that the existing licence remains valid. Licence PL 12 contains a number of specifications and conditions one of which is the requirement for a Safety Case, accepted by the Director of Petroleum and Royalties Division, DoIR, to be in place. The current Apache Energy Ltd Safety Case for the PL 12 plant was accepted by the Director, PRD of the DolR in December 2007.

The Safety Case requirement was first introduced in September 1998, in PL 12 Variation No. 9P/97-8. A safety case is described as "A document containing information relevant to the identification, assessment, management and monitoring of matters, and other information, relevant to safety in the Licence area".

The WA Petroleum Pipelines Act 1969, as it applies on Varanus Island, is administered by DolR. NOPSA has provided, on request, technical advice on occupational health and safety matters to DolR under a contract between NOPSA and DolR.

The WA Petroleum Submerged Lands Act 1982 (P(SL)A82)

The section of the 12" sales gas pipeline directly affected by the incident is located above the low water mark and is outside the jurisdiction of the P(SL)A82. However, the P(SL)A82 does apply to those sections of the Apache Varanus Island pipelines seaward of the low water mark, and under the WA Petroleum (Submerged Lands) (Pipelines) Regulations 2007, consent is required to construct and operate such pipelines. The Regulations require that a person must not undertake construction activities relating to a pipeline unless the WA Minister has consented to the construction and a pipeline licensee must not operate a pipeline under the licence unless the WA Minister has granted consent to operate the pipeline.

Specifically, pipeline licences were issued by the DolR under this Act, to Apache Northwest Pty Ltd. and its co-licensees for the offshore sections of certain pipelines. Of the 6 pipelines crossing the NNE beach of Varanus Island, 5 were licensed under this legislation.

The relevant licences are:

• TPL 1 for the 8" Harriet crude oil line • TPL2 for the 30" crude export line • TPL5 for the 6" Harriet gas line • TPL8 for the 12" sales gas pipeline • TPL 13 for the 16" sales gas pipeline

The Apache 12" Infield gas pipeline from the Campbell and Sin bad offshore facilities to onshore Varanus Island is not licensed under this legislation. The reason for this is not known to the investigators.

Under the P(SL)A 82 and its regulations, Apache is required to have a Safety Case in force for offshore facilities in these waters. Prior to March 2007, DolR was the sole regulator of this Act. Subsequently, powers were conferred on NOPSA such that the Safety Case for these offshore facilities must be accepted by NOPSA. In general, the

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P(SL)A 82 regulating the offshore facilities around Varanus Island continues to be administered by DoIR, with NOPSA administering the regulation of health and safety matters.

The Apache Energy Ltd Varanus Hub Safety Case is currently a combined Safety Case document, encompassing the offshore facilities and the onshore process plant. The Safety Case addresses the requirements of both the P(SL)A 82 and its regulations, and the requirements of the onshore pipeline licences issued under the PPA69 (PL 12, 29 and 30) relating to the onshore process plant. The current Safety Case was accepted in October and December 2007 by NOPSA and the DolR respectively, each according to the jurisdictions outlined in this paragraph .

Further, effective March 2008, the WA P(SL)Act 1982 and its regulations, requires a licensee of licensed pipelines to have a Pipeline Management Plan (PMP) in force. The PMP must contain information pertaining to the matters described in Part 4 Division 2 of the WA Petroleum (Submerged Lands) (Pipeline) Regulations 2007. The PMP must be accepted by the WA Minister. A Pipeline Safety Management Plan (PSMP), defined as the components of a PMP that provide for the safety and health of persons at or near the pipeline, must be assessed and accepted by NOPSA. The WA Minister may not accept a PMP without NOPSA having first notified the Minister that the PSMP is acceptable.

The Apache Energy Ltd Operational PMP, currently in force for all pipelines operated by Apache on the North West Shelf, was accepted by DolR under its delegated powers, in March 2008.

Applicable Codes and Standards

The applicable standards for the design , operation and maintenance of pipelines are typically specified in the pipeline licences. For the Apache 12" sales gas pipeline, the licences (PL 12 for the Varanus Island section, TPL8 for the subsea section , and PL 17 for the bnshore mainland section) state that AS2885 -1987 Pipelines - Gas and Liquid Petroleum (the SM code), is the applicable standard . Section 13 of this standard deals with operation and maintenance.

This standard was later superseded by AS2885.1-1997, AS2885.2-1995, and AS2885.3-1997. The current versions of AS2885 are:

• AS2885.1 - 2007 Pipelines-Gas and Liquid Petroleum-Design and • Construction. • AS2885 .2 - 2007 Pipelines-Gas and Liquid Petroleum-Welding . • AS2885.3 - 2001 Pipelines-Gas and Liquid Petroleum-Operation and • Maintenance. • AS2885.4 - 2003 Pipelines-Gas and Liquid Petroleum-Offshore submarine • pipeline systems. • AS/NZS2885.5 : 2002 Pipelines-Gas and Liquid Petroleum-Field pressure

testing.

AS2885.4 - 2003 refers the reader directly to Det Norske Veritas offshore standard DNV-OS-F101 Submarine Pipeline Systems, and disapplies AS2885.1, 2, 3 and 5. Section 10 of DNV-OS-F101 deals with the operation, inspection and repai r of submarine pipeline systems.

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The basis of design for the 12" sales gas pipeline, cites the following standards related to the cathodic protection system applied to the pipeline:

• AS/NZS 2832.1: 1986 Cathodic Protection of Metals Part 1 Pipes and Cables and Ducts 1985.

• DNV-RP-B401 Recommended practice for Cathodic Protection Design 1986

6. INVESTIGATION ACTIVITIES

6.1 Activities at the Apache Operated Facilities on Varanus Is land

The investigation team arrived at the Apache operated facilities on Varanus Island at 17:30 WST on Wednesday 4 June 2008. The investigation team left the island at 12:15 WST on Saturday 7 June 2008.

During the period spent investigating the incident at the island, the investigation team carried out the following tasks and activities:

• Held a meeting with Apache's management and an ALERT representative (an investigator contracted by Apache) to explain the purpose and process of the investigation .

• Viewed a sample of Apache's incident photographs to develop a perspective on the nature of the incident.

• Inspected the incident site, took photographs , made sketches (see Attachment 5 & 6)

• Interviewed and took formal statements from 9 people who were witness to the events of the 3 June 2008 and from one person with information relevant to the investigation (listed in Attachment 7). The personnel interviewed provided information about:

General conditions and activities at the Apache facilities on the island prior to the incident Their own activities and location within the Apache facilities prior to the incident The sequence of events of the incident Post incident events Their own actions Actions taken by Apache

• Requested and obtained information from Apache (drawings, reports, photographs) Attachment 2, Table 2, identifies documentation received from Apache at site.

• Discussed the manner of removal, transport and testing of samples from selected pipes from the incident site.

• A process by which the integrity of the testing to be carried out by Apache and its contractors could be assured was agreed between DolR and Apache. This process entailed:

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Arrangement for the pipe samples to be transported and tested in a manner that would ensure the continuity of evidence. This involved acceptance by DolR of the transport protocol. Verification of pipe samples arriving at the PearlStreet testing laboratory, Welshpool WA, which involved one of the investigators witnessing the unpacking of pipe sample containers.

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Acceptance by DolR of the non-destructive and destructive test protocol. Arranging access to the test results and report. DolR agreement for the destructive tests to proceed after being satisfied that non-destructive tests have been satisfactorily completed.

6.2 Activities Subsequent to Site Visit of the Apache Facilities on Varanus Island

The investigators identified a number of areas as relevant or potentially relevant, within the scope of the investigation. These formed the basis of the lines of investigation developed and (see Attachment 2 Table 1 for details), they are summarised below:

1. Confirmation of the location of the incident site. 2. Examination of the incident site including external examination of the

damaged pipes. 3. Reviewing extent of plant damage. 4. Establishing the number and distribution of personnel at the Apache facilities

on Varanus Island. 5. Identifying activities taking place at the Apache facilities on the island prior to

the incident. 6. Establishing the operating parameters and status of the Apache production

plant and the affected Apache pipelines. 7. Establishing the sequence of events. 8. Examining potential personnel exposure. 9. Identifying post incident events and their relevance to the incident, including:

• Actions taken by individuals, in particular Apache process operators and supervisors,

• Immediate response to the incident (personnel musters, incident monitoring and personnel evacuation).

10. Identifying the failure mode of the pipelines, which included review of the pipe sample test results and independent experts rep'orts, so far as available.

11. Identification of applicable legislation, including subsidiary regulatory approvals relating to the Apache pipelines and facilities.

12. Review the relevant pipelines design and protection systems. 13. Examining the adequacy of Apache's pipeline inspection, maintenance and

monitoring regime, including past inspection, maintenance and monitoring records for selected pipelines.

14. Identifying pipeline inspection, monitoring and maintenance requirements as stipulated in relevant licences, codes and standards.

15. Resources and structure of Apache's pipeline inspection and maintenance group.

16. Identifying causes of the incident. 17. Identifying possible breaches of legislation.

The following sources of information were used during the investigation (for details see Attachment 2 Table 1 & 2):

• Site visits • Witness statements taken from Apache staff and its contractor staff • Pipe inspections and sample test results • Independent specialist opinions • Legislation, licences, codes and standards • DolR records

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• Apache documentation (drawings, procedures, manuals, reports, data)

Over 250 documents, principally Apache documents, (see Attachment 2 Table 2), including several reports and manuals, were examined by the investigating team. This information was provided by Apache after some delay and following reinforcement of DolR requests . Review of these documents, conducted for the purpose of extracting relevant information, was carried out in parallel with, and informed, the other investigation activities which included:

• Developing the lines of investigation • Arranging and conducting interviews (16 persons in total were interviewed -

Attachment 7) • Managing information (requesting, receiving and monitoring) • Liaising with Apache on testing of pipe samples • Arranging for the engagement of two independent specialists:

A metallurgist; and A pipeline corrosion expert

• Analysing data • Report writing

The investigators also reviewed reports (Attachment 2, Table 2, reference item 259) relating to testing of samples of pipelines removed from the incident site. In total, 11 pipe samples were removed from the incident site . Of the 11 samples, 4 were considered to be of primary importance to the investigation. These were the samples removed from either side of the rupture point on the 12" sales gas pipeline, and from either side of the rupture point on the 12" Campbell/Sinbad pipeline.

As discussed in section 6.1, a testing protocol was agreed by DolR and Apache, detailing the tests that would be undertaken. These tests were both non destructive and destructive in nature. The tests proposed included:

Visual examination Dimensional assessment Surface deposit sampling and analysis Ultrasonic examination Radiographic examination Examination of fracture surfaces Crack testing Examination of the Metallurgy Mechanical testing Chemical analysis

At this time, no testing has been undertaken that would permanently alter the pipe samples from their 'as removed' condition. Findings from the test results received to date are discussed in section 7.8.

6.3 Impediments to the Investigation

Early in the investigation, the investigation team identified the need to interview key Apache personnel about, for example, matters pertaining to the pipeline inspection , monitoring, maintenance, and repair regime.

Requests for interview were declined by Apache.

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Apache subsequently agreed to respond to written question sets developed and submitted by the investigation team to the individuals concerned. Apache then advised the DolR investigator that no responses to written questions would be provided within the investigation time scale. Consequently, the investigators were unable to question the Apache personnel listed below who were considered to have knowledge of matters pertaining to the incident, and potentially able to provide verification of the investigators' understanding of the events leading to the incident:

• Production Manager • Senior Integrity Engineer (current and previous occupier of the position) • Corrosion Technician • Person in Charge of Harriet A platform

It is noted that the investigation team was provided with a document entitled "Corporate Response by Apache Northwest Pty Ltd to the Questions posed by the DolR for the Production Manager, Ivor Alexander" on 8 September 2008; over 7 weeks after these written questions were issued to Apache.

Delays were also experienced in accessing the reports arising from the examination and testing of the pipeline samples removed from the incident site. The initial indication was that all non-destructive and destructive tests arranged through Apache would be completed within eight weeks from the date of the incident. The non-destructive test results were provided to the investigators 11 weeks after the incident. The destructive testing phase, and some elements of the non destructive testing that involve physically altering the pipe samples, have not yet been carried out. At the time of writing, it is estimated that reports on these aspects of the testing will not be available until mid November 2008.

These matters directly impacted on the ability of the investigation team to develop its findings within the agreed time period and resulted in aspects of some lines of the investigation not being fully settled. However, it is considered that resolution of these matters is unlikely to significantly change the nature of the findings of the investigation: . . .

7. FINDINGS

Notwithstanding the difficulties encountered by the investigation team in sourcing information, the following findings have been produced following analysis of the available information.

Each finding is marked with the letter F and a number. Attachment 2, Table 1, provides cross reference between the individual finding and the information source on which the finding is based.

F1. The incident resulted in the shut down of all Apache operated Varanus Island production facilities and connected platforms, including gas export to the mainland.

7.1 Environmental conditions

F2. The environmental conditions on the island on the day of the incident were as follows:

• Wind: East/South East, 10 knots with 12 knots gusts • Waves: 0.9 m (significant height) • Visibility: good

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7.2 Sequence of Events

7.2.1 Events leading up to the incident

F3. In the hours leading up to the incident the activities at the Apache facilities on the island could be best described as normal and routine. There were no notable production process upsets in the days leading to the incident or immediately prior to the incident on 3 June 2008.

F4. The production plant operated as normal, with no major work outside of routine maintenance activities, being conducted on the day.

F5. Contractors were undertaking project works within the plant areas. New (Mars) compressor installation activities, mainly civil works, were being carried out by Apache contractor personnel approximately 130 metres from the incident site. Tie in pipe spools were being fabricated in advance of a planned shutdown. Appropriate work permits were in place for these works.

F6. At the time of the incident there were 150 personnel on the island and 16 personnel offshore on the Apache Harriet A and Gibson platforms (166 in total).

7.2.2 Sequence of Incident Events

F7. On the basis of personnel interviews and information provided, the investigation team believes the sequence of events on the 3 June 2008, was as follows:

3 June 08

•

• •

•

•

•

• •

•

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13:30

13:50

13:55

14:00

14:18

14:27 14:27

14:30

Harriet Joint venture plant in steady state operation, 12" sales gas pipeline operating at 11100kPa, 16" sales gas pipeline operating at 13200kPa.

·12" initial explosion heard (12" gas sales line ruptures followed by 12" Campbell/Sinbad pipeline). ESD initiated in the control room. Plant blow-down commenced. Muster of personnel completed at two locations (control building and main camp). Large fires observed to north side of Apache HJV plant. ERT deployed to assess (from a distance) the incident site. ERT deploys 3 water monitors to cool equipment adjacent to the incident site and returns to the main camp. DBNGP Control Room contacted. Request was made to remotely shut in Compressor Station no 1 (CS1). Following further discussions it was agreed that DBNGP would continue to take gas from Apache to reduce pressure in the 12" and 16" sales gas lines. BK helicopter and an Apache service boat (Loligo) sent to observe the incident from a distance, take photographs, observe the nature of the incident and damage, and report to the Apache Field Superintendent. 16" sales gas line and 6" Harriet gas line rupture. Apache control room personnel evacuated to the main camp. Second muster of all personnel completed. Helicopter departs for the mainland (CS 1) to confirm and if necessary isolate the 12" and 16" sales lines (the concern was that the contents of the 16" line could feed through the inter-connector valve to the 12" sales gas line).

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•

•

•

•

•

•

• •

•

• • •

4 June 08

15:00

15:15

15:26

15:50

16:02

17:10

18:00 18:35 19:41

07:00

Boat (Loligo) departs the incident site to pick up personnel from Apache Harriet A and Gibson platforms Two operators went to the 'A' crude storage tank and closed the inlet valve, to prevent the crude from feeding the fire if the crude export line was damaged / ruptured. The remaining tanks ('B' and 'C') were inactive and isolated prior to the incident. Meter station at CS1 shut in automatically due to decreased pressure in 12" and 16" sales gas lines - gas flow into DBNGP stopped. Boat (Loligo) evacuated all 16 personnel from Apache Harriet A and Gibson platforms to the Apache facility muster area at Varanus Island. Apache personnel sent by Helicopter to CS1 reported that 16" and 12" lines had been isolated manually at CS 1. GGT Control Room contacted by Apache. GGT flow control valves closed. BK helicopter arrives at Barrow Island (from CS 1). Boat (Loligo) moves towards the incident site to observe the fires from a safe distance. BK helicopter returned to Varanus Island, evacuation of non-essential personnel commenced. Boat (Loligo) returned to Varanus Island. ERT sent to fight small brush fires (returned 19:35). Last helicopter evacuation flight from Varanus Island, 14 person skeleton crew stayed overnight on the island. ERT team deployed to site. Main fires out. ERT extinguish small brush fires.

7.3 Potential for Injury

F8. In general, personnel visits to the NNE beach are discouraged due to environmental concerns. The beach has little recreational utility. The operational visits are infrequent and short, mainly for the purpose of: .

• Inspecting the pipelines crossing the beach, and • Setting up a suck back pump on the 30" crude export line every time the oil is

loaded to the visiting tanker (usually once a month).

F9. After the incident Apache introduced formal instructions preventing unauthorised access to the NNE beach.

F10. Although there were no reported injuries or fatalities , the incident had the potential to result in casualties. The lack of casualties was mainly due to the following factors :

• no personnel were on the NNE beach on the day of the incident, • no personnel were working in the northern corner of the HJV gas plant

adjacent to the incident site. Four people nearest the incident site were working in the HJV gas plant (approximately 110 -130 meters away from the point of rupture on the beach); and

• no personnel were using the road on the embankment between the HJV gas plant and the beach when the first explosion occurred .

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7.4 Incident Location and Layout

F11 . The incident occurred on the pipeline beach crossing (NNE beach) behind the Apache Harriet Joint Venture (HJV) gas plant.

F12. A corridor containing 6 pipelines in close proximity to each other traverses the NNE beach (see Attachment 5, Photos 4a) & 4b). Looking from the beach towards the gas plant, from left to right, the pipelines are:

Pipe Pipe details Date installed Surface/buried (Licence) rupture site.

16" sales gas 75 mm Concrete weight coating pipeline

4 mm Asphalt enamel corrosion 1999, 20 year

variation 9P/97-8 to coating (sub-sea section) surface PL 12, TPL 13, &

design life

variation 1 OP/97-8 to PL 17 6" Harriet to Stabilisation by trenching and Varanus Island Gas mattresses offshore-no concrete line weight coating 1988/89,20

buried year design life

variation 1/91-2 to 0.4 mm fusion bonded epoxy PL 12 & TPL5 corrosion coatin~ 30" crude oil export 65 mm concrete weight coating line

1986, 20 year Surface/partial

O.4mm fusion bonded epoxy design life buried

PL 12 & TPL2 corrosion coating 12" sales gas 25mm concrete weight coating pipeline

1992, 25 year 4.5mm Asphalt enamel corrosion

design life buried

Variation 1/91 -2 to coating (sub-sea section) PL 12, TPL8, PL 17 Campbell/Sinbad to 25mm concrete weight coating. Varanus Island 12" infield pipeline 4mm Asphalt enamel corrosion 1992, 15 year

buried coating design life Variation 1/91-2 to PL 12. 8" Harriet to Stabilisation by trenching offshore Varanus Island oil

10 year design line, O.4mm fusion bonded epoxy buried corrosion coating life

(PL 12, TPL 1)

The 6 pipelines are unequally spaced .

The smallest separation gap of 167 mm - as measured on 6 June 2008 -was between the 12" sales gas line, the first pipeline to rupture, and the adjacent 12" Campbell/Sinbad line, the second pipeline to rupture (see Attachment 6, Sketch 1).

This separation distance is a contributory factor in the consequential rupture of the Campbell Sinbad infield 12" gas pipeline, following the initial rupture of the 12" sales gas pipeline.

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at

Review of the formal safety assessment section of the Pipeline Management Plan for the pipelines indicated that Apache had recognised this as a potential threat. The document identifies the threat as "failure of an adjacent pipeline". Control measures were identified as being "minimum separation between pipelines", and "inspection testing and monitoring of the adjacent pipeline". The investigators found no information indicating what the minimum separation distance should be. See discussion in section 7.9 with respect to pipeline IMMR activities.

7.5 The Incident

F13. There is no evidence that there were any specific events (e.g. process upsets) immediately prior to the incident, which may have triggered or contributed to the incident.

F14. Four Apache pipelines ruptured during the incident:

• The 12" sales gas pipe line (ruptured on the beach) • The Campbell/Sinbad to Varanus Island 12" infield gas pipeline

(ruptured on the beach) • The 16" sales gas pipe line (ruptured at the top of the seawall

banking) • The 6" Harriet gas line (ruptured on bend adjacent to 16" SDV 301 L)

F15. Prior to the incident, the pipelines which ruptured were being operated by Apache within their design operating pressures and temperatures as shown below.

Pipe Carried Operating Operating substance Pressure Temperature

(kPa) (DC).

Maximum Actual Maximum Actual Allowable Allowable

12" sales gas pipeline to Dry sales

14500 11100 80 59 mainland gas

Campbell/Sinbad Wet gas to Varanus Island and 9700 5160 80 n/a 12" infield produced pipeline water 16" sales gas pipeline to Dry sales

20160 13200 70 50 mainland gas

6" Harriet to Wet gas Varanus Island and

9900 3570 65 34 Gas line produced water

F16. The composition of the fluids conveyed in the pipelines on the day of the incident was generally within the range quoted in the PMP; the one exception being the carbon dioxide (C02) level for the 12" and 16" sales gas lines, which was between 3.2 and 3.6 mol%, above the 3.0 mol% quoted in the PMP and 3.1 mol% stated in the TPL8 licence. Although CO2 is known for its

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corrosive properties, the increased level of CO2 is not seen as a factor contributing to this incident in view of the identified failure modes of the pipelines.

F17. The first line to rupture was the 12" sales gas line. This finding is based on the following:

• Witness statements taken from control room operators and the investigators' review of control room data provide evidence that immediately following the initial rupture, the pressure reading in the control room on the 12" sales gas pipeline dropped from 11100 kPa to O. There was no pressure drop indicated on other lines at that time.

• Investigators on-site visual examination and subsequent forensic testing by Pearl Street testing laboratory, Welshpool WA of the 12" sales gas line revealed extensive external corrosion (pitting) and thinning of the pipe wall (from approx 11 mm down to approximately 1.5 mm in a section of the rupture area). The corrosion was observed along the full length of the ruptured section of the pipe, between 2 o'clock and 8 o'clock.

F18. The second line to rupture was the Campbell/Sinbad to Varanus Island 12" infield gas pipeline. This is based on the following:

• Witness statements indicating 2 explosions were heard initially. • The close proximity of this line to the 12" sales gas line. • The investigators' review of the Varanus Island facility control room data

provided by Apache is inconclusive in indicating the time of this second rupture, but does indicate that this line was intact prior to the rupture of the 12" sales gas line.

• The investigators' visual examination and subsequent forensic testing by Pearl Street, of the Campbell I Sin bad to Varanus Island 12" infield gas pipeline, adjacent to the 12" sales gas line, revealed similar but smaller areas of external corrosion. No other pipes in the vicinity showed similar levels of external corrosion .

F19. The initial explosions occurred on the beach. The nearest elements of the Apache HJV gas plant are located approximately 75m away, but are approximately 5m above the level of the pipelines on the beach. Because of this, the jet fires from the ruptured ends of the 12" pipelines were deflected by the embankment up into the air, and did not impinge directly into the plant areas (Attachment 5, Photos 2 and 3).

F20. The ruptures created a crater on the beach approximately 8m wide X 2m deep X 30m long which exposed the buried pipes (Attachment 5 Photo 5).

F21. No obvious remote source of ignition has been identified. There was no hot work being undertaken near the rupture site at the time, i.e. there was no work, involving for example burning, welding or grinding, directly capable of providing an ignition source. Potential sources of ignition of the hydrocarbon release include:

• Pieces of ruptured pipes sparking when hitting each other or other objects,

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• Stones, pieces of concrete and other debris hitting the HJV gas plant (structure, electrical equipment and cabling) and causing sparks.

F22. As a result of the ruptures, the surrounding areas, including the NNE part of the Apache HJV gas plant, were showered with rocks, smaller stones, gravel, and pieces of concrete stability coating thrown from the pipelines Attachment 5 photo 12 shows the largest rock (17.5kg) found within the Apache HJV plant area. Persons interviewed indicated this rock and other debris, were not present within the plant area prior to the incident.

F23. Based on a review of tests conducted to date by PearlStreet testing laboratory, Welsh pool WA on the ruptured pipe samples indicate that:

• The 12" sales gas line ruptured due to a mechanical failure • The Campbell/Sinbad to Varanus Island 12" infield gas pipeline failed

due to the combination of mechanical and heat impact from the 12" sales gas line rupture, explosion and fire

• The 16" sales gas line failed due to heat impact/radiation from earlier fires and explosion

• The 6" Harriet gas line failed due to heat radiation/impact

F24. The 16" sales gas line, failed high on the embankment close to the 16" Shut Down Valve (Attachment 5 Photo 10). Discharge from this line Get fire) was away from the plant, towards the beach.

F25. The 16" sales gas line SDV valve position indicator in the Apache Varanus Island facility control room showed that the valve was "in transit", suggesting that it did not close properly on activation at the time of the incident. Subsequent examination by Score Pacific concluded that the valve did move to the closed position following the ESD initiation (see Attachment 5 Photo 16). The most likely cause of the "in transit" indication in the control room was a faulty or misaligned valve position indicator. . .

F26. Following the initial ruptures and fire, three water monitors were activated by the Apache Emergency Response Team (ERT) to create a protective water cooling curtain between the fires and the plant (Attachment 5, Photo 2). This action appears to have been effective in preventing more widespread damage to the Apache HJV gas plant from radiant heat.

F27. At the time of the incident, the prevailing wind was blowing across the pipelines, pushing the flames across the face of the HJV gas plant, not towards it (see Attachment 4 Drawing 2).

F28. The metering station at the mainland compressor station (CS1) shut in automatically due to pressure drop in both 12" and 16" lines. Later, the lines were also isolated manually at this location by Apache personnel sent by helicopter.

F29. The Apache production facilities on the island were isolated and blown down through the elevated flares.

7.6 Post Incident Events

F30. All personnel were accounted for within approximately 20 minutes after the incident, and initial muster alarm.

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F31. Out of 166 personnel on Varanus Island:

• 152 were evacuated off the island. Of those:

145 were evacuated by helicopters to Barrow Island where they were provided with temporary accommodation. This required 13 helicopter flights by 5 helicopters (one BK helicopter, two S76s and two Super Pumas). 7 were evacuated by boat to Dampier.

• 14 personnel remained on the island overnight to monitor the situation.

7.7 Damage

Four pipelines ruptured during the event (see F14 for details).

F32. There was substantial damage due to fire and heat radiation to the Northern corner section of the Apache HJV gas plant, including the Hot Oil unit, and piping around the pipeline Pig launchers/receivers. This included physical destruction of, or damage to, pipe racks, structures, electrical equipment, vessels, valves and piping (see Drawing 2 in Attachment 4 & photos in Attachment 5).

There was also some damage to the adjacent Apache HJV and ESJV plants from flying debris and heat radiation.

Detailed assessment of the plant damage has not been carried out as part of this investigation as this matter is outside the investigation Terms of Reference (see Attachment 1 for details).

7.8 Failure Mechanism of the 12" Sales Gas Pipeline at Varanus Island NNE Beach Crossing

The following explanation of the 12" sales gas pipeline failure mechanism is based on the information available to date, which did not include final results and analysis of forensic tests of pipe samples;

Pipe Sample Examination and Testing

At the time of writing, no testing that would permanently alter the pipe samples from their 'as removed' condition, has been undertaken. The testing conducted to date indicates the following:

• 12" sales gas pipeline The pipe samples removed from both sides of the rupture point exhibit extensive pitting due to corrosion of the external surface along the entire length of the samples. Pipe wall thickness assessments are continuing, however the results to date indicate that over a significant area, the wall thickness has been reduced from a nominal 11.1 mm down to approximately 3mm to 4mm in areas, with some areas immediately adjacent to the rupture point significantly less than that.

The pipe samples removed from both sides of the rupture point are devoid of corrosion coating. It should be noted that the sample removed from the south

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side of the rupture point was largely exposed by the explosion and was exposed to the subsequent jet fire and heat following ignition of the released gas. The sample removed from the north side of the rupture remained largely buried following the explosion and ignition of released gas and was therefore shielded from the effects of the fire. It is therefore concluded that the corrosion coating originally applied to this pipe section had deteriorated and become dis-bonded prior to the incident occurring, and had not simply burned away.

• 12" Campbell! Sinbad pipeline The pipe samples removed from both sides of the rupture point exhibit areas of localised pitting due to corrosion of the external surface. Pipe wall thickness assessments are continuing, however the results to date indicate that, in general, the pipe wall thickness has been maintained.

Despite being exposed to fire and radiant heat, the pipe sample removed from the south side of the rupture point exhibits what is thought to be corrosion coating residue over intermittent areas of the pipe sample along its full length. This residue is flaking away from the pipe surface. Pitting of the external pipe surface is evident beneath this residue.

The pipe sample removed from the north side of the rupture point shows no signs of pitting to the external surface, and is devoid of corrosion coating residue. It should be noted that this section of pipe was closest to the adjacent 12"sales gas pipeline and the heat effects from the ignited gas flowing from the ruptured end of that pipe.

Pipeline Corrosion

12" sales gas pipeline

In order for" corrosion of the external surface of the 12" sales gas pipelin·e to take place, the corrosion coating must have failed. This coating failure may have been due to incorrect application, damage to the coating either prior to, during, or after installation, or loss of adhesion of the coating during operation. The evidence available to date is insufficient to determine why the corrosion coating may have failed.

F33. The extent and depth of corrosion indicates it is likely that the corrosion occurred over a significant period.

The evidence also suggests that the cathodic protection system was ineffective in providing an adequate level of protection to the section of pipe in the environment where sea water either saturates or drains away from the beach sand (refer photos 14 &15 Attachment 5, and section 7.10).

As a result, due to ongoing external corrosion, the pipeline wall thickness was progressively reduced in a section of the rupture area from the original nominal 11.1 mm down to 1.5 mm (this includes thickness reduction / necking due to material yield).

F34. Although pre-yield wall thickness measurements are not available, the evidence indicates that on the day of the incident the pipe wall was subject to a stress level beyond its minimum yield strength. Progressive metal yield and increase in the pipe diameter raised stresses beyond the ultimate tensile

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strength of the metal resulting in the catastrophic failure of the pipeline. This occurred under normal process operating conditions (see F. 15)

F35. There is no evidence to indicate that the localised external pitting and resulting loss of wall thickness evident on the pipe samples removed from the beach crossing section of the 12" Campbell / Sinbad pipeline was a factor in this incident.

Apache Pipelines IMMR (Inspection Maintenance and Monitoring Regime)

Apache Safety Case and Pipeline Management Plan

As discussed in section 5.2, the pipeline licence PL 12 held by Apache NorthWest Pty Ltd and its co-licensees, in conjunction with the P(SL)A82 and its regulations, require that a Safety Case (SC) be in force for Varanus Island and for the offshore facilities around Varanus Island. Apache has a single safety case document addressing the management of the onshore Varanus Island plant and all of the offshore facilities connected to Varanus Island. This document is known as the Varanus Hub Safety Case. A component part of the Varanus Hub Safety Case is the Safety Management System description (SMS), which describes how safety is managed on these Apache facilities. The safety management system provides for all activities envisaged to be undertaken on these facilities, with a focus on:

• The identification of hazards and assessment of risks to the health and safety of people associated with undertaking those activities;

• The implementation of control measures to reduce the risk to personnel to a level as low as reasonably practicable;

• The ongoing inspection, monitoring and maintenance of control measures associated with these risks.

One of the key elements of the Apache Safety Management System (SMS) is Element 7 "Integrity Management". This 'SMS element sets out in general terms, ' Apache arrangements for inspection, maintenance and monitoring of process facilities, wells and pipelines throughout their lifespan. Apache has an Integrity Policy which sits alongside its Occupational Health and Safety Policy. In order to meet the commitments of these policies, management systems have been developed. These are:

• The Maintenance Management System • The Corrosion and Inspection Management System • The Maintenance strategy for safety critical equipment

In addition to the safety case requirement, the P(SL)A82 and its regulations require that a Pipeline Management Plan (PMP) be in force for facilities that are pipelines. A component part of the PMP is the description of the management system, which sets out arrangements for managing all pipelines operated by Apache on the North West Shelf. Its primary aim is to ensure that the integrity of the pipelines is maintained throughout their operational life cycle while safeguarding personnel and the environment.

The Apache SC and PMP management systems are supported by a suite of Apache policies, systems, manuals and procedures pertaining to integrity management. Two documents, in particular, set out the specifics of the current framework for inspection, monitoring, maintenance, and repair (IMMR) activities relative to pipelines. These documents are:

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• Onshore Pipeline Inspection Manual (AEL Document OP-14-MG-001) and • Underwater Inspection Manual (AEL Document AE-00-MG-006)

The Onshore Pipeline Inspection Manual is stated to be applicable to the "onshore" section of the 12" sales gas pipeline. Onshore is defined as being that part of the pipeline between landfall and the pipeline termination or Pig launcher/receiver. The term "Landfall" is not defined; however it is reasonable to conclude that this document is applicable to the section of pipeline on the beach at the Apache facility on Varanus Island at which the rupture occurred , since this area is readily accessible on foot. The cover sheet for this document indicates it was developed in 1997. The most recent revision is Revision 4, issued for use on the 22/3/06. At the time of writing , and on the basis of the information provided by Apache, it is unclear what document was in place and applicable to the onshore section of the 12" sales gas pipeline prior to the creation of the Onshore Pipeline Inspection Manual.

The Apache Onshore Pipeline Inspection Manual states that the philosophy for inspection shall be consistent with that described in the applicable pipeline standard , AS2885.3-2001. The standard states that pipeline surveillance and inspection frequencies shall be based on the past reliability of the pipeline, historical records, current knowledge of its condition, the rate of deterioration of the pipeline and statutory requirements. In lieu of this approach, the Onshore Pipeline Inspection Manual cites that an annual frequency is to be applied. The document describes a typical inspection programme for onshore pipelines:

• Annual topographical survey in surf zone/beach area • Annual visual inspection of unburied pipework to determine the condition of

the coating , general corrosion and physical damage • Annual cathodic protection (CP) survey to ensure an adequate level of

cathodic protection is being maintained at each test post • Ann\Jal line walk checking condition of CP anq other marker posts,. including

the use of gas detector to identify any leaks • Annual checks on surge protection systems and static earth system

The Underwater Inspection Manual describes the means by which Apache manages and performs underwater inspection activities on all of its offshore assets. It includes the subsea sections of pipelines. The document describes 4 different levels of pipeline survey:

• Level I surveys are undertaken using side scan sonar and Remotely Operated Vehicle (ROV). Should a level I survey indicate that damage has occurred , then a level II survey is undertaken.

• Level II surveys are carried out using ROV and comprise a visual and cathodic protection survey. Should significant structural damage be detected then a Level III survey should be undertaken.

• Level III surveys are undertaken using ROV or divers to examine specific characteristics of anomalies identified during the Level II survey. Any significant damage detected during a level III survey would become the basis for initiating a level IV survey.

• Level IV surveys consist of underwater non-destructive testing of areas based on the results of Level III surveys. In addition to this, Intelligent Pigging of the pipeline may be considered to assess the inside condition of the pipeline, and particularly any loss of wall thickness that may have occurred.

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The document states that level 1 surveys shall be conducted at least every 3 years, Level II surveys at least every 3 years, Level III surveys after the discovery of suspected defect areas, and level IV surveys as required.

There is no prescribed frequency for undertaking intelligent pig surveys in either the onshore or under-water portions of the pipelines.

Codes and Standards

The pipeline licence PL 12 variation 1/91 -2 held by Apache NorthWest Pty Ltd and its co-licensees, as applicable to the section of the 12" sales gas pipeline located onshore Varanus Island, states that the pipeline will be designed, constructed, operated and maintained in accordance with Australian Standard AS2885-1987 Pipelines-Gas and Liquid Petroleum (the SM Pipeline Code). This standard was in force in 1992 when the 12" sales gas pipeline was designed, constructed, installed and commenced operation. This standard has evolved since 1987 such that the current version now comprises 5 parts, each dealing with a specific area. Australian Standard AS2885.3-2001 Pipelines-Gas and Liquid Petroleum Part 3, discusses the requirements for the Operation and Maintenance of pipelines. The requirements of the earlier version and the current version are slightly different.

AS2885-1987 is prescriptive in that it determines the frequency of inspection of the CP system for a pipeline. The standard requires that:

• Surveys of cathodic protection potential shall be made at intervals of not more than 12 months, or where cathodic protection potentials may be affected by stray DC currents, survey intervals of cathodic protection potentials shall be approved. Galvanic anode cathodic protection installations shall be monitored at intervals of not more than 12 months to ensure their operation.

• the efficacy of a galvanic anode ' cathodic protection installation shall be established within a period of not more than 12 months of its installation. The installation shall be monitored at intervals of not more than 5 years to ensure operation, but intervals may be shortened during the approach of the end of the design life.

AS2885.3-2001 does not include any prescriptive requirements that dictate the frequency of inspections or surveys for operating pipelines. The standard states that pipeline surveillance and inspection frequencies shall be based on the past reliability of the pipeline, historical records, current knowledge of its condition, the rate of deterioration of the pipe and statutory requirements .

Apache references this later version of the standard in its Onshore Pipeline Inspection Manual.

Pipeline Licence

Apache is also required to comply with the prescriptive requirements for pipeline inspection, maintenance, monitoring and reporting set out in the relevant pipeline licences. For the section of the 12" sales gas pipeline located onshore Varanus Island, the relevant licence is PL 12 variation 1/91-2.

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PL 12 variation 1/91-2 states that:

• The licensee shall be responsible for installing and monitoring the cathodic protection test points.

• The licensee shall, when required, submit to the Director a report in writing outlining the results of the corrosion surveys and the details of any resulting action by the licensee.

• The licensee shall carry out an annual external survey of the pipeline after the cyclone season and the results of the survey shall be submitted to the director in writing.

There are no other prescriptive requirements relevant to pipeline inspection or surveys within this licence variation.

7.9.1 Apache Resources and Organisation

Element 1 in the SMS section of the Apache Energy Ltd . SC and PMP outlines the personnel responsibilities and organisational arrangements within Apache.

Whilst the Apache Managing Director has the overall responsibility for Apache operations on Varanus Island, the Apache Production Manager has the responsibility for the implementation of Apache's integrity policy, including the implementation of the pipeline inspection and corrosion management measures.

Based on a review of Apache documents , two senior engineers report to the Production Manager. These are:

• The Senior Integrity Engineer; principally responsible for the identification, implementation and maintenance of the facilities (including pipelines) corrosion and inspection activities, condition monitoring and recommendation of r~medial actions. Key .responsibilities include:

Corrosion Risk Assessment Development and maintenance of the inspection plans Scheduling and planning of intelligent Pigging activities Development of procedures and instructions relating to corrosion and inspection activities Analysis of results, assessment of anomalies and recommendation of corrective actions

• The Senior Corrosion Engineer; principally works in coordination with the Senior Integrity Engineer in areas of corrosion monitoring, coating and materials selection. Notable responsibilities include:

Development of corrosion monitoring obligations based on all known hazards Recommendation regarding materials selection for repairs, replacement and additions to facilities, Management of coatings, including selection of systems, monitoring and repair

Other personnel in the integrity management group include: • Subsea Engineer • Field Superintendent and • Support personnel and contractors

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The organisational structure applied to facility integrity management is shown in detail on page 8 of the Apache Integrity Management and Competencies Description Doc No AE-91-IO-001, Rev 0, issued January 2008. The investigators were unable to establish, on the basis of the information provided by Apache, whether:

• There are present incumbents of all positions and • Which positions are held by Apache employees and which by contractor

company employees.

On the basis of the available information, the investigators were unable to determine whether the level of resources (historically and at the time of the incident) provided by Apache was adequate, and whether it was a factor which contributed to this incident. In particular, no information was produced by Apache or found by the investigators that demonstrated the adequacy of the provided resources (personnel , finance and material) and how the required level of resources was maintained over time.

The investigators noted , however, that the Lloyd's Register report titled "Apache Energy Limited, PL 12 Validation Summary Report May 2006 - April 2007" dated 10 May 2007, states on page 14:

"It was observed that manning levels, at Apache, in various disciplines, are low with key competencies contracted out and / or residing with specific individuals. "

F36. Apache's management of personnel resources and organisational responsibilities for pipeline integrity management may have been a contributory factor in the incident.

7.9.2 Apache's Use of Contractors

Apache makes use 'of large and small contractor companies including individual consultants to fulfil resource needs in areas where its in-house expertise is limited or unavailable. The use of contractors extends to pipelines (installation, inspection, monitoring and assessment) and involves:

• Corrosion monitoring, chemical and cathodic protection contractors; • Pigging contractors; • Integrity and pipeline engineers; • Corrosion experts and coating contractors • Diving contractors • ROV and side scan survey contractors • Inspection contractors and Certifying Authorities (e.g. Lloyd's, ABS or

DNV) .

Apache has a number of systems and procedures for the management of contractors. These include:

• "Assurance of contractor safety management" (Doc. No. AE-00-ZF-037) • "Procedure for preparation and approval of contractors for service" (Doc. No.

AE-91 -IQ-030 Rev C) • "Procedure for mobilising contractors to site" (Doc. No. AE-00-ZF-012)

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Since the commencement of Apache operations at its Varanus Island facilities a number of specialist companies have been contracted by Apache to carry out inspections, surveys and assessments, relating to the integrity, including inspection and maintenance arrangements, of the Apache operated pipelines at or connected to the Apache facilities at Varanus Island.

Whilst the reports issued by Apache's contractors have often contained recommendations for improvement, their general conclusions with respect to the condition of equipment (i.e. the pipeline) and how its integrity is managed are positive. Some example comments from such reports are:

• Sales Gas line 5 year integrity review SP-14-RL-067, May 2007, by Subsea Developments:

"There are no findings from the integrity management processes performed for the sales gas pipelines that provide any reason for any changes to the ongoing IMR activities that are not already being addressed in the current risk assessments and anomaly tracking and close out practices"

"The AEL Pipeline Integrity Management process is generally following the requirements of AS2885 and any specifics included in the pipeline license for the Sales Gas Pipelines".

• Lloyd's Report titled "Apache Energy Limited, PL 12 Validation Summary Report May 2006 - April 2007" dated 10 May 2007 states on page 2:

"Provisions were found to be in place with continuous improvement process to ensure safety of the operational phase and technical integrity for ongoing operations of the Varanus Island whole plant and facilities covered by PL 12 as fit for purpose for the next 21 years"

and' on page 7

"based on preliminary review from initial information gathering and gap analysis, the operation was considered to be covered by a comprehensive integrity management system, sufficient to validate operation for approval for pipeline licence revalidation for the next 21 years"

Broad statements such as these may have been based on limited information, and not on a comprehensive physical inspection of equipment, or a review of all aspects of its operation , inspection, maintenance and repair.

This is particularly relevant to the 12" sales gas pipeline, with 1 documented inspection by a contractor of the Varanus Island shore crossing section carried out since its construction in 1992.

F37 In general this investigation found that the link between source data and conclusions in the reports were unclear. Apache apparently used these reports as a basis to plan the inspection, maintenance and repair activities of its pipelines and to assure itself and the regulator that the pipelines were safe to operate.

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7.9.3 Apache 12" Sale Gas Pipeline IMMR

The investigation team requested from Apache all records of inspection, monitoring, maintenance and repair activity documentation related to the 12" sales gas pipeline, since the commencement of operations in 1992.

Following a review of the documentation provided, the investigation team compiled an IMMR summary table detailing the activities undertaken, when they were undertaken, and importantly, to what part of the 12" sales gas pipeline the activity applied. This chart is included as Attachment 8 Table 1.

This was then compared against those activities that Apache was required to undertake, either by their own documentation, relevant standards, or by conditions in the applicable pipeline licences held by Apache NorthWest Pty Ltd. and its co­licensees. These requirements are summarised in a similar table included as Attachment 8 Table 2.

The investigation team found that:

F38. Variation 1/91-2 to PL 12 (the pipeline licence applicable to the onshore Varanus Island section of the Apache 12" sales gas pipeline) states that the licensee shall carry out an annual external survey of the pipeline after the cyclone season and the results of the survey shall be submitted to the Director in writing.

From the information provided, regular annual external surveys of the section of the pipeline onshore Varanus Island did not occur. It is recognised that surveys of subsea and mainland sections of the pipeline have occurred. However, in the period 1992 to 2008, there were two documented visual inspections of the section of the pipeline onshore Varanus Island. It is unclear whether the results of these reports were provided to the Director, PRD of DolR as required. These surveys are detailed in the following docu mentation :

• Varanus Island Ultra shallow water and onshore pipeline inspection, OP-14-RU-002, performed in October 2004.

• 2007 Onshore Pipeline Inspection workbook, Sept 2007.

The ultra shallow water and onshore pipeline inspection in 2004 was undertaken by a contractor to Apache, Netlink Inspection Services. The report highlights 10 anomalies, one of which pertains to the 12" sales gas pipeline. This anomaly related to an area of missing weight coating at pipeline location KP69.703. Apache has provided no information indicating what action was proposed or taken to rectify this anomaly. Shortly after the incident on 3 June 2008, it was noted that this anomaly was still present and apparently degenerated since 2004.

The 2004 report also indicates that there were areas of corrosion and damage on the onshore section of the pipeline however these were apparently not significant enough to be categorised as anomalies in the report. No cathodic protection readings for the 12" sales gas pipeline were taken during this inspection.

The 2007 Onshore Pipeline Inspection Workbook is a record of Apache inspections as required by the Apache Onshore Pipeline Inspection Manual

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for a number of pipelines located onshore Varanus Island , including the 12" sales gas pipeline. The workbook includes a completed, pipeline general visual inspection record sheet for the Apache 12" sales gas pipeline. A single CP reading is provided. No anomalies are recorded. However, it is noted that a significant proportion of this onshore section is buried , and hence inaccessible for external visual inspection unless excavated . Excavation of the Agincourt pipeline appears to have been undertaken in 2007 according to the Onshore Pipeline Inspection Workbook for that year. It is not clear from the inspection report whether this excavation was for inspection purposes or for remedial works.

A review commissioned by Apache in 2004 highlighted the lack of pipeline inspection data from the shore crossing zones on Varanus Island:

Review of Apache Energy Pipelines 2004, SP-14-RF-003.01/03, by QCL International cites:

"In general it was found that very little inspection data was available for onshore pipeline sections on Varanus Island, shore sections and subsea risers ."

"The onshore pipelines on Varanus Island are monitored visually during standard operations on the island and inspection data is therefore often not documented. It is also recommended that the inspection procedures for offshore and onshore inspections should be modified to ensure that the offshore section is inspected during HAT, and the onshore section is inspected during LAT, ensuring sufficient overlap"

"At present the shore zones do not seem to be included in either of the standard inspection work scopes"

F39. Variation 1/91 -2 to PL ·12 (the pipeline licehce applicable to the onshore Varanus Island section of the 12" sales gas pipeline) states that the licensee shall be responsible for installing and monitoring the cathodic protection test points. The licensee shall, when required, submit to the Director a report in writing outlining the results of the corrosion surveys and the details of any resulting action by the licensee.

From the information provided , monitoring of the cathodic protection system onshore Varanus Island occurred in 2004, 2006, 2007 and 2008. Records of these inspections are detailed in:

• Offshore pipelines-onshore section cathodic protection survey August 2004, OP-14-RU-003

• VI Offshore pipework monitoring 18/6/06 • VI Offshore pipework monitoring 18/6/07 • 2007 Onshore pipeline Inspection workbook, Sept 2007. • VI Offshore pipework monitoring MCC building 2008

The investigation team were unable to find any evidence of the Director, PRD of DolR requiring any reports outlining the results of the surveys.

F40. The Apache Onshore Pipeline Inspection Manual is applicable to the section of the 12" sales gas pipeline located onshore Varanus Island.

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This document indicates that a typical inspection programme for onshore pipelines comprises:

• Annual topographical survey in surf zone / beach area • Annual visual inspection of unburied pipework to determine the

condition of the coating, general corrosion and physical damage • Annual cathodic protection (CP) survey to ensure an adequate level of

cathodic protection is being maintained at each test post • Annual line walk checking condition of CP and other marker posts,

including the use of gas detector to identify any leaks • Annual checks on surge protection systems and static earth system

From the evidence provided to the investigators by Apache, no annual topographical surveys of the pipeline in the surf/beach zone area were undertaken. As discussed above, visual inspections of the pipeline were undertaken on 2 occasions, 2004 and 2007. Also as discussed above, cathodic protection readings from the 12" sales gas pipeline in the beach crossing area were taken in 2004, 2006, 2007, and 2008.

F41 . From the information provided by Apache, it appears that Apache did not undertake any maintenance or repair activities on the section of the 12" sales gas pipeline onshore Varanus Island since its installation in 1992.

F42. On the basis of the information provided by Apache, an appropriate documented regime for pipeline inspection, maintenance, monitoring and repair is in place, and this regime is consistent with that required by the relevant standards and the requirements of the pipeline licence. However, the available evidence indicates that some aspects of these systems and processes may not have been rigorously implemented since the pipeline was installed in 1992.

7.10 Apache 12" Sales Gas Pipeline and Cathodic Protection System Design

The 12" sales gas pipeline was designed and constructed in accordance with AS2885 -1987. The following table summarises key design parameters for the 12" sales gas pipeline:

P' r Ipe me Outside diameter 324 mm Maximum allowable working pressure 14500 kPa Wall thickness 11.1 mm Design temperature 10-80 DC Material API- 5L X60 Minimum yield strength 413 MPa Corrosion coating 4.5 mm Asphalt Enamel Corrosion allowance 3mm Weight coating 25 mm Substance to be conveyed Natural gas (as specified in the PL 12

and TPL8) Design Code AS 2885 Year installed 1992 Design life 25 Years

AS2832 Bracelet anodes - offshore section onl

Page 31 of 88 OBJ 10: A53510

The Apache Pipeline Management Plan, document SP-90-RL-002, is applicable to the full length of the 12" sales gas pipeline. The PMP provides a detailed description of the 12" sales gas pipeline . All significant pipeline accident events for the pipeline are identified and assessed. Mitigation measures are identified to reduce the risk of significant pipeline accident events to a level that is as low as reasonably practicable.

The formal safety assessment section of the PMP identifies external corrosion as a hazard to the 12" sales gas pipeline in the subsea, shore crossing and onshore sections of the pipeline. For the onshore section, external corrosion is assessed as being of medium risk. At the shore crossing and subsea sections, external corrosion is assessed as being of low risk.

For each hazard , physical and procedural preventative or mitigation measures, are identified as follows :

Protection measure Onshore Shore crossing Subsea section section section

Physical protection measure - Anti applicable applicable applicable

corrosion coating Physical protection measure - Cathodic

applicable applicable Protection system Procedural protection measure -Inspection testing and monitoring, applicable including IP survey Procedural protection measure-Inspection testing and monitoring, applicable applicable including ROV/IP survey

From the above it can be seen that Apache has identified two physical barriers against external corrosion of the pipeline for the shore crossing and subsea sections of the pipeiine. . .

However, only one physical protection measure is identified for the onshore section, this being the anti corrosion coating. Inspection testing and monitoring is cited as a procedural barrier. The drawings included in the PMP indicate that the onshore Varanus Island section of the 12" sales gas pipeline is not considered to be protected by a cathodic protection system.

In practice however, based on the nature of CP readings being taken and other factors , it appears that Apache considered that the cathodic protection system in place and active on the subsea and shore crossing sections of the 12" sales gas pipeline, carries over onto the Varanus Island onshore section and provides some protection against corrosion.

In order for corrosion to take place, the anti-corrosion coating must fail, either due to mechanical damage or loss of adhesion . The evidence available to date is insufficient to determine why the corrosion coating may have failed .

F43. Based on examination of samples of the ruptured pipelines by Pearl Street Testing Laboratory, Welsh pool WA and the investigators, the anti-corrosion coating at the beach crossing was ineffective due to mechanical damage or loss of adhesion resulting in dis-bondment from the pipe.

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The CP system's role is to prevent corrosion if the first barrier, the corrosion coating, has failed.

The key elements of the system are sacrificial anodes attached to the pipeline. In this configuration the generated currents flow from the anodes through the sea water (electrolyte) to the pipeline. Areas which the current leaves are corroded (sacrificial anodes). Areas where the current enters (pipeline) are protected.

The effectiveness of the CP system is dependent on the ability of the current to flow between the anode and the pipe. Subsea, current will flow freely through the seawater medium. However, at the beach crossing section the ability of the current to flow is affected by the environmental conditions. At the beach crossing section the pipeline was buried in sand which was either saturated with, or drained of, sea water, dependent on tidal movements. This results in fluctuations in sand resistivity, with drained sand having higher resistivity affecting the CP current flow. To counter this effect, more negative CP potentials are needed. Such potentials were not available for the beach crossing section from the offshore bracelet anodes. There were no other (onshore) anodes installed to provide cover for this section of the pipe.

F44. On the basis of the available evidence, no aspects of the design of the 12" sales gas pipeline have been identified (excluding the CP system), which contributed to this incident.

F45. The available evidence indicates that the design of the CP system for the offshore section of the 12" sales gas pipeline, would not offer sufficiently negative potentials to protect the wet / dry transition section of the beach crossing of the Apache 12" sales gas pipeline located on Varanus Island.

8. CONCLUSIONS

The following conclusions are drawn by the investigation team based on the evidence available to date.

The information gathered during the investigation was examined using the TapRoot® root cause analysis technique. The event analysis chart developed by the investigation team (Attachment 9) shows the sequence of events, existing conditions and causal factors.

8.1 Immediate Cause of the Incident

The immediate cause of the incident was the rupture of the Apache 12" sales gas pipeline due to excessive stresses in the pipe wall.

Thinning of the pipe wall as a consequence of extensive external corrosion of the pipe resulted in excessive stresses culminating in rupture of the pipe at the beach crossing at the Apache facility on Varanus Island.

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8.2 Main Causal Factors

The main causal factors of the incident were:

1. Ineffective anti-corrosion coating at the beach crossing section of the Apache 12" sales gas pipeline, due to damage and/or dis-bondment from the pipeline.

2. Ineffective cathodic protection of the wet / dry transition zone of the beach crossing section of the Apache 12" sales gas pipeline on Varanus Island.

This is because:

a) Sufficiently negative cathodic protection potentials required to provide effective cathodic protection in sandy environment were not available from the existing offshore bracelet anodes,

b) No onshore anodes were installed on the onshore/beach section of the pipeline.

3. Ineffective inspection and monitoring by Apache of the beach crossing and shallow water section of the Apache 12" sales gas pipeline on Varanus Island.

This is because:

Page 34 of 88

a) The external corrosion problem was not detected and addressed at this location, although the available evidence indicates that the corrosion progressively affected the pipe over a period of 15 years or more until the pipeline failed .

b) The technique used to take cathodic protection readings to monitor the operation of pipeline protectidn was inappropriate for the environment in which the readings were taken as it did not allow for the effect of changing resistivity in the wet and dry sandy environment. The limited cathodic potential measurements taken suggested to Apache personnel that the pipeline was adequately protected, which was not the case.

c) Although the Apache 12" sales gas pipeline was built in 1992, there is a lack of historical documentary inspection data related to the Varanus Island onshore section of the 12" sales gas pipeline, with evidence limited to:

• One ultra shallow water and onshore pipeline inspection undertaken in 2004. This inspection covered the onshore beach section of the pipeline but did not comment on the buried sections of pipeline .

• One documented general pipeline inspection undertaken in 2007. This inspection covered the onshore beach section of the pipeline but did not comment on the buried section of pipeline.

d) The Apache inspection regime did not specifically address the transition section between the subsea and shore crossing sections of

OBJ 10: A53510

the pipeline, by for example undertaking inspections at both HAT and LAT to ensure full inspection coverage in this area.

8.3 Other Factors

The following factors were also found to be relevant to the incident:

1. No Intelligent Pig inspection of the 12" sales gas pipeline was carried out since the pipeline was constructed in 1992. Although this is not a prescribed requirement, such an inspection could have led to the prevention of the incident occurring as it would have detected the pipeline wall thickness metal loss at the Varanus Island beach crossing.

In response to specific questions from the investigators on this matter, Apache stated in a letter ("Corporate Response by Apache Northwest Pty Ltd to the Questions posed by the DolR for the Production Manager, Ivor Alexander") dated 8 September 2008 that "In 1998, there was some discussion by a consultant of whether pigging might be done on the 12" line, with a focus on the mangrove area of the mainland side of the line. The suggestion was not adopted."

This statement may be referring to the Apache commissioned QCL International Corrosion risk assessment of certain pipelines and plant equipment, undertaken in 1997/8. The resulting report, LTS, Sinbad, Campbell and Compressor Station 1 Corrosion Risk Assessment and Inspection Scheme, HE-00-MN-003 Rev 1 issued Sept 1998, considered the risks of internal and external corrosion to the 12" sales gas pipeline.

The report states that that the risk to the pipeline from internal corrosion is minimal.

The report also states that the ·pipeline is protected from the risks from external corrosion in the subsea section, as long as the mitigation measures in place, i.e . the corrosion coating and cathodic protection system, are monitored, maintained and inspected.

However, the report does recognise that there is a significant risk to the pipeline due to external corrosion in the coastal and onshore sections. Section 7.5 of the report states:

"The onshore section, particularly in the coastal mangrove areas, is less certain. Variation in local soil conditions means that the current requirement for full protection varies considerably. The location and conditions mean that close interval potential surveys are difficult, and so detailed checks for adequate potential in all areas are not currently performed."

"Coastal mangrove waters are more aggressive towards coatings and require higher polarising currents than open, deep cold seawater. The combination of warmer conditions, biological activity and tidal effects, mean that the coastal section is more at risk of external failure than any other part of the pipeline. Therefore it is important that cathodic protection surveys be carried out. "

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The report discusses the intelligent pigging option:

"The requirement for intelligent pigging on this line is dictated by the external corrosion hazard, particularly in the coastal mangrove section of the line. The most serious risk to the continuing integrity of the pipeline is where the coating has disbonded, creating a region of wet, bare metal shielded from corrosion protection current. Corrosion may occur despite adequate cathodic protection potentials. This is a risk on all coated pipelines, but is most significant on onshore/inshore lines, particularly under tube wraps and shrink type field weld coatings. The only methods of detecting such failures are either to excavate all field joins, or to run an intelligent pig."

The report concludes:

"The economic and safety consequences of a failure of the sales gas pipeline, coupled with the difficulty of surveying the coastal section, and the risk of coating disbondment failure mean that regular intelligent pigging of the line is justified. To save cost, this survey may be concentrated on the coastal and onshore sections of the line. The period is arbitrary - a figure of 5 years is suggested, meaning that an intelligent pig run will be necessary next year. Further surveys will be required depending on the results ."

Whilst the report does not specifically mention the Varanus Island beach crossing section it is clear that Apache was made aware of significant external corrosion risks to the coastal and onshore sections of the pipeline.

Apache provided no explanation as to why the recommendation to conduct Intelligent Pigging to survey / monitor the pipeline for external corrosion, was not followed .

2. It is noted that an Intelligent Pig inspection' of the 12" sales gas line was scheduled to be conducted subsequent to the repair works carried out as a result of the incident on 3 June 2008.

3. Close proximity of the pipelines to each other in the beach crossing zone on Varanus Island was a factor in the escalation of the event.

9. POSSIBLE BREACHES OF LEGISLATION

The investigation identified the following sections of legislation within the Petroleum Pipeline Act 1969 where possible breaches may have occurred:

Section 36A: Work Practices

A licensee shall operate the pipeline specified in the licence of which he is the registered holder in a proper and workmanlike manner and shall secure the safety, health and welfare of persons engaged in operations in connection with the pipeline

Section 38b: Marking of Pipeline and maintenance etc. of property

A licensee-

(b) shall maintain the pipeline in good condition and repair; and

Page 36 of 88 OBJ /0: A53510

The investigation also identified the following section of legislation within the Petroleum Pipelines Regulations 1970 where possible breaches may have occurred:

Regulation 10: Pipeline Construction and operation requirements

The construction and operation of a pipeline shall be carried out-

(a) in a proper and workmanlike manner; (b) in accordance with good pipeline construction and operation practice; and (c) in such manner as to ensure the safety health and welfare of persons engaged in

the construction or operation

Some findings contained in this document may also constitute non-compliance with pipeline licence conditions.

Page 37 or88 OBJ 10: A53510

10. ATTACHMENTS

Attachment 1 -

Attachment 2 -

Attachment 3 -

Attachment 4 -

Attachment 5 -

Attachment 6 -

Attachment 7 -

Attachment 8 -

Attachment 9 -

Page 38 or88

Investigation terms of reference

Lines of investigation Table 1- Lines of investigation Table 2 -Information Log

Maps Map 2 - North West Shelf oil and gas facilities

Drawings Drawing 1 - Varanus Island production facilities Drawing 2 - Beach explosion

Photographs Photo 1 Photo 2

Photo 3 Photo 4 a) Photo 4 b) Photo 5 Photo 6 Photo 7 Photo 8 Photo 9 Photo 10 Photo 11 Photo 12 Photo 13 Photo 14

Photo 15

Photo 16

Sketch

Varanus Island Varanus Island fire and explosion incident, view from helicopter Varanus Island NNE beach, incident site Ruptured 12" pipelines Ruptured 12" pipelines Explosion crater 30" crude export line, suck back pump cage Seawall banking Damaged gas plant 16" SDV (gas export line) Ruptured 16" sales gas line Ruptured 6" Harriet gas line Debris in HJV gas plant (compressors) area Seawall banking water and jet fire erosion Ruptured section 12" sales gas line, external corrosion and wall thinning Ruptured section 12" sales gas line, external corrosion Inside view of 16" SDV, ball in closed position

Sketch 1 - Incident site, pipelines proximity

List of interviewees

Pipeline IMMR activities Table 1 - Pipeline IMMR activities Table 2 - Prescriptive requirements

Event Analysis Chart

OBJ 10: A53510

Attachment 1

Investigation into pipeline rupture and fire on Varanus Island which occurred on Tuesday, 3 June 2008

TERMS OF REFERENCE

Investigation to be undertaken by DolR /NOPSA Investigation Team 9 July 2008 (revised)

BACKGROUND

Western Australia's Department of Industry and Resources is assessing the damage at the Apache Varanus Island facilities, which are licensed under the Petroleum Pipelines Act 1969 (PPA1969) as PL 12 and/or the Petroleum (Submerged Lands) Act 1982 as TPL 8.

The Department of Industry and Resources is responsible for regulating the safety and integrity of facilities on Varanus Island under the Petroleum Pipelines Act.

The Department has been administering these responsibilities with input from the National Offshore Petroleum Safety Authority (NOPSA) under a service level agreement and other sources.

The Department has authorized an investigation into the incident which is currently being undertaken by a team consisting of two NOPSA

. representatives ~nd one departmental inspector appointed under the Petroleum Pipelines Act.

The "Incident" means the failure of pipelines on the NNE beach approach and the resultant explosions and fire.

PURPOSE

The purpose of the investigation is to:

1. Fulfil the request from the Director, PRO of DolR on 4 June 2008 to assist in the conduct of an investigation under the terms of the Service Contract dated 6 July 2007 between WA DolR and NOPSA.

2. Gather information and interview people in a manner that does not compromise potential legal action. (This to be achieved through the direction of the WA DolR representative on the investigation team).

3. Identify the facts and events relevant to the Incident. 4. Identify the likely cause(s) of the Incident. 5. Identify potential breaches of legislation based on the legal advice and

direction provided by Dol R. 6. Formally gather evidence consistent with the requirements of Dol R as

advised by the investigation team DolR Inspector.

Page 39 of 88 OBJ 10: A53510

SCOPE

The investigation will endeavour to address:

1. The pertinent sequence of events on Varanus Island during the Incident.

2. The likely cause(s) of the Incident. 3. Any actions and omissions by the operator of the Varanus Island

facility, or its contractors, leading up to the Incident and during the Incident that may have contributed to the cause of the Incident.

4. The identification of any potential for injury to persons arising directly from the fire and explosion(s) at the time of the incident.

The investigation will be conducted in the context of, and will have regard to, good industry practice, the commitments made by the operator in respect of its operation of the Varanus Island facilities and in the context of the applicable laws and licence requirements as detailed to the investigation team by DolR.

The investigation will not address: • Events that occurred after the incident except where they are directly

relevant to items 1- 4 of the scope detailed above. • Assessment of the damage to facilities on the island except where

directly relevant to the scope detailed above. • Adequacy of the arrangements for repair and re-instatement of

damaged plant and equipment.

REQUIREMENTS

DolR may need to require or provide for certain matters pertaining to the investigation. These include:

1. Obtaining information from the Operator and other parties that is considered by the investigation team to be required to assist the investigation.

2. Exercise of powers under the WA Petroleum Pipelines Act 1969.

3. Engagement of independent experts relating to, for example, metallurgy and corrosion mechanisms.

DELIVERABLE

On completion of the investigation, the team will provide a Report to the Director, PRD of DolR detailing the findings of the investigation.

Page 40 of 88 OBJ 10: A535 10

J

FURTHER SUPPORT

Officers of NOPSA will work with the Director, PRD to review the Report and provide assistance in the consideration of potential enforcement action or prosecution, meeting with the SSO as appropriate.

Page 41 of 88 OBJ 10: A53510

Attachment 2 Table 1 - Lines of investigation

Report finding Table 2

No Area covered Information source or Information Log section (Item. No)

(Ref. no)

• Site visit by F11, F12, investigators F18, F19, 1 Incident location • PL 12, TPL 8 F21, F23, 5, 53, 54, 56,57

• Apache documents F24 (maps and drawings)

• Apache documents Personnel, number (POB records for VI and distribution, on and offshore 1-4, 5, 8, 38, 40·44,

2 Varanus Island and platforms) F5, F6, 54,46,62,63,64, adjacent offshore • Apache active work F10 68, 69, 71, 72, 75, platforms on 3 June orders and permits 114,231 2008. (PTW

• Witness statements Plant operation on • Apache control room 1-4,38,40-42,47-Varanus Island on 3

3 June 2008 prior to the data F3, F4, 50,68,69,71,72,75,

incident (shut down • Apache P&IDs F5, F21 81-83,114,198-

sectionsj. • Witness statements 206

Operating parameters for pipelines on the • Apache control room NNE beach on 3 June data

4 2008, prior to the • PL 12 & TPL8 F13, F 2,3,38,47-50,63, incident (pressures • PMP 15, F16 198·206 temperatures, • Witness statements composition of carried fluids)

• Apache active work Activities/jobs carried orders and permits F3, F5, 1-4, 7,8,38,40-42,

5 out on Varanus Island (PTW) F10, F13, 62,63, 68, 69, prior to the incident • Witness statements F21 71,72,75,114

Environmental • Apache document F2, F21,

1-4,38,40-42,52, 6 conditions on 3 June (weather forecast) F23, F27 61, 63, 68, 69,

2008 • Witness statements 71,72,75,114

• Apache control room data

• Helicopters movement log

• Pipelines non-destructive and F1, F7, 1-4,38,40-42,47-destructive test F14, F17,

50, 55, 59, 62, 63, 7

Sequence of events on results F18,F24 65,68, 3 June 2008 • Pipelines inspection F25,F 69,71 ,72,75-83,93,

and monitoring 26, F28, 113-117,198-209 records F30

• Pipeline corrosion and metallurgical expert reports

• Witness statements

Page 42 of 88 OBJ ID: A53510

Report finding Table 2

No Area covered Information source or Information Log section

(Ref. no) (Item. No)

8 Personnel visits to the Witness statements F8. F9. 1-4.38,40-42.63,

NNE beach • F10 68,69,71,72,75,114

Apache procedures/standing • Apache documents 1-4, 38,40-42, 63,

9 orders regulating F9 68,69,71,72,75,114, access to the NNE • Witness statements 119 beach Use of the road on the

1

embankment (between • Apache documents 1-4, 38,40-42, 63, 10 the gas plant and the F10 68, 69, 71, 72, 75,

beach) by personnel • Witness statements 11,119

• Apache documents (personnel distribution records,

1-4,5,8,38,40-42, Personnel exposure emergency response, 11 during incident VI drawings) F10, F19 53,54, 57, 63, 68-

• Site visit by 69,71,72,75,114,

investigators • Witness statements

12 Tanker offoading • Apache documents F8, F10 90 frequency (tanker visits log)

Setting up up/testing of • Apache documents 13 crude export line suck (procedures, work F8 86-89

back pump orders)

• Site visit by F1, F14, 1-4,6, 38,40-42, 63, 14 Damage to plant investigators F19, F21,

68,69, • Witness' statements

F26, F32, 71,72,75,114 F33 Functioning of • Apache control room 1-4,38,40-42,51 ,

15 pipelines ESD data

F24 62, 63, 59, 68, 69,

equipment (ESD • SDV test results 71, 72, 75, 81-83, valves) • Witness statements 114,226

• Apache individual Incident response on personnel incident Varanus Island: response records

• Personnel muster • Apache control and and evacuation radio room data

• Shutting • Helicopter logs down/staring up • Apache plant (including documentation 1-4, 38,40-42,45, actions near the including: F25, F26, 53,55, 56, 62-64,

16 incident site and - mainland CS1 F28, F29, 65, 68, 69, 71, 72, the mainland P&IDs compressor storage tanks

F30, F31 75, 92, 93, 113, - 114,116, 241-244 station CS 1) P&IDs • Incident - P&IDs for fire

assessment and fighting and monitoring detection systems

• Plant shut down • Information from and blow down DGNB and GGT

pipeline operators

• Witness statements

Page 43 of 88 OBJ /0: A53510

Repart finding Table 2

No Area covered Information source ar Information Log section

(Ref. na) (Item. No)

Applicable legislation - 0 PPA 69, P(SL)A 82 Pipeline Licenses, SC 0 PL 12, TPL8,

17 & PMP and 0 PMP Sect 9.2 requirements 0 Varanus Hub Safety

Case 12" sales gas pipeline design and data: 0 Apache 0 design and documentation/recard

fabricatian s (including drawings

18 specifications and and reports) F17, F22, 84,85, 185,237-data, 0 PL12, TPL8 F44 240

0 installation records 0 PMP 0 site (NNE beach 0 DolR records

geology). 0 Codes and standards

0 Apache Anti- corrosion coating documentation

F17, F22, 20-25,41,154, 19 and CP for 12" sales 0 Codes and Standards F43,45 163, 164,182,245,

gas line. 0 PMP 246, 248 0 PL 12, TPL8

Regulatory approvals required/obtained by Apache as stipulated in PLs (PL 12 & TPL8),

20 e.g. for CP design, 0 DolR recordslfiles 11 .9 intervals of inspections, corrective actions (repairs)7

Pipeline inspection 0 Relevant Australian

requirements and DNV standards 21 (legislative, codes and

PL 12, TPL8 Sect 9.2

247,248,258 standards, good 0

& 11 .9 industry practice 0 Pipeline corrosion

expert report

Apache pipeline 0 Apache IMMR Inspection policies, manuals and

9-37, 41, 63, 94-Maintenance and procedures

112,122-194,210-22 Monitoring Regime 0 Apache/contractor F38-F42 230, 232-235, 247, (IMMR)- past and assessment reports 248,258 current of the IMMR

0 Witness statements Structure of Apache Pipeline Inspection Maintenance and Monitoring DepartmenUSection,

Apache documents Sect 23 past and present,

0 11 .9.1, 247, 254,255

including number of 0 Witness statements F36.

personnel, positions, responsibilities, reporting lines.

Page 44 of 88 OBJ 10: A53510

Report finding Table 2

No Area covered Information source or Information Log section (Ref. no)

(Item. No)

Resources allocated Apache documents 41,63,189-192, 24 by Apache over time to • F36 pipeline IMMR. • Witness statements 247,254,255

• Apache documents 28,30,31,35,37, Use by Apache of • Contractor pipeline

95-112,122-152, contractors and 155-157,159-176,

25 independent condition and IMMR F37 177-179,180, 195, specialists. assessment reports 196,197,210-216,

• Witness statements 218-226, 247 Records of inspection, surveys and • Apache pipeline maintenance (repairs) inspection and survey

26 carried out on reports F38-F41 17,25,171,175, pipelines crossing • Apache/contractor 176,188 NNE beach, in pipeline assessment particular, on 12" sales reports qas line.

• Viewing by investigators of ruptured pipes (on site) , and pipe samples at Pearl Street

F17, F23, laboratories 27 Pipelines failure mode Non-destructive and F33, F34, 259 • F35 destructive test

results

• Pipeline corrosion expert report

• Metallurgist report

28 Incident causes All available information Sect. 12 relevant to this incident

29 Possible breaches of

PPA69 Sect. 9.2,

legislation • 13

Page 45 of 88 OBJ /0: A53510

Attachment 2 Table 2 - Information Log

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(/)

« (!)

~

-oJ -0 LL. I> -oJ ~ Wg :I:~ (/)

l-(/) W ~ :I: l-e::: 0 z

Attachment 3 North West Shelf Oil & Gas Facilities

, Map 1 (in the body of the report) taken from inset

• I H

~

•

,

~

~ ii ii!!liilil!!illiil!iiii.iil iiiil

Page 58 of 88 OBJ 10: A53510

Attachment 4

''''011: 1 ~ru

to :"tt ' (lIO "'-.

\ \

'.,

Drawing -2 taken from inset

, ., .' ~

/

Drawing 1 - Apache Varanus Island production facilities

Page 59 of 88

...... , ... ~

OBJ ID: A53510

Willd dil'l'l'tioll

Approx. plant damaae area

Pipeline explosion

Storoot T .nk 1250 .uuuoO""

Drawing 2 - Location of explosion on beach

Page 60 of 88

loading line

Approx 100m radius

X11 I

~X12

\

OBJ ID: A53510

Attachment 5

Top camp muster

_ . . ~:....

Photo 1 - Varanus Island

T

Photo 2 • Varanus Island fire and explosion incident, view from helicopter

Page 61 of 88 OBJ fD: A53510

Attachment 5

HJV gas plant 16" sales gas line rupture

-.. ,

12" gas lines rupture

Photo 3 - Varanus Island NNE beach, incident site

16" sales gas pipeline

6" Harriet gas line

8" Harriet oil line

4 a) 4b)

Photo 4 a) & b) - Ruptured 12" pipelines

Page 62 of 88 OBJ 10: A53510

Attachment 5

Photo 5 - Explosion crater

Photo 6 - 30" crude export line valve cyclone protection cage

Page 63 of 88 OBJ 10: A53510

Attachment 5

T;~' •

Photo 7 - Seawall banking

16" SDV

Photo 8 -Damaged gas plant

Page 64 of 88 OBJ 10: A53510

Attachment 5

Photo 9 -16" SDV (gas export line)

,'. , .; t ', : .

'.'

'. ,

-. Photo 10- Ruptured 16" sales gas line

Page 65 of 88 OBJ ID: A53510

Attachment 5

Photo 11 - Ruptured 6" Harriet gas line

•

• >

, .

, .. . ~

17.5 kg rock

"_I~-

Photo 12 - Debris in HJV gas plant (compressors) area

Page 66 of 88

..,.

OBJ 10: A53510

Attachment 5

.. . '.

Photo 13 - Seawall banking water and jet fire erosion

Photo 14 - Ruptured section 12" sales gas line, external corrosion and wall thinning

Page 67 of 88 OBJ 10: A53510

Attachment 5

Photo 15 - Ruptured section 12" sales gas line external corrosion

Page 68 of 88 OBJ 10: A53510

Attachment 5

Photo 16 -Inside view of 16" SDV, ball in closed position

Page 690188 OBJ /0: A53510

Attachment 6

t To Apache VI production Facilities

If)

'" 0> If)

Ol

~ • Ol <Dc ,.... :.::

Protective coating (concrete & asphalt enamel)

flow 1'l' directionU

6000

If)

'" 0>

Q) ·c ~

'" IOl <o~

950

Ol ~ C Ol .-.><-c 0>

~~ - '" °0 C'">_

1400

If) Ol ~ C cu:..= If)

" ~ ~O>

Not to scale - dimensions as measured on 6 June 2006

167

~ 0383

550 '" uO>

"'= .oOl c.o UjCl. _ E Ol N(\lC ,....0:.=

1050

~I Ol C

..... :.: 0>:: ·c 0 ~

'" Ol IU :: 2 CO t)

Attachment 6 - Sketch 1 - Incident site, pipelines proximity

Page 70 of 88 GBJ 10: A53510

Attachment 7

Last Name Given Names Position/Company Date of Interview Interview Location

1 Beckford Peter Corrosion 6 June Varanus Technician/Apache 2008 Island

2 Bennett Zachary James Construction 21 July Clough

Superintendent! 2008 Clough

Perth

4 Davies Ivor Haora ScaffolderlWilson 4 July CFMEU Pipe Fabrication 2008 Perth

3 Drake Tony Instrument 19 June Brockman Electrical 2008

WA DolR Fitter/Chamber of

Perth Commerce and Industry

5 Embleton Brian Kevin Construction 6 June Varanus

Manager VIIEmbo 2008 Island

Engineering Ltd 6 Fletcher Wayne Kevin Process 5 June Varanus

Operator/Apache 2008 Island 7 Jackson Christopher Safety 6 June Varanus

VanHomnQh ManaQer/Apache 2008 Island 8 Morck Justin Michael Production 5 June Varanus

Operator/Apache 2008 Island 9 Paton Ross Adam Varanus Island 7 June

Field 2008 Varanus Superintendent!Apa Island che

10 Simcock Wayne Douglas Maintenance 5 June Varanus Supervisor 2008 Island

11 Smith Gavin James Electrician/Apache 5 June Varanus 2008 Island

12 Solomon Paul William Rigger 9 July CFMEU

ScaffolderlWilson 2008 Perth

Pipe Fabrication 13 Symington Vincent David Onshore 5 June

Varanus Production 2008

Island Supervisor/Apache

14 Thomas Grant Elliot ScaffolderlWilson 4 July CFMEU

Te-Tahu-O- Pipe Fabrication 2008 Perth

KawatpuaranQi 15 Welten Mark Anthony Medic Safety 6 June Varanus

Officer/Apache 2008 Island 16 Wong Ling Chang Instrument 20 June WADolR

(James) Technician/Apache 2008 Perth

Page 71 of 88 DBJ ID: A53510

Page 72 of 88

Attachment 8

Apache Pipeline IMMR Activities

Table 1- IMMR Activities

Pages 73 -79

OBJ 10: A53510

16" Sales Gas Pipeline: installed 1998/9

12" Sales Gas Pipeline: installed 1992/3

324mm Sales Gas Pipeline 1992 In spectio n report Nov 1992, SP-14-

UL-006

II

Onshore sales gas pipeline cathodic] 1993 protection survey May 1993. OP·14.

1993

RU-005

324mm Sales Gas Line Pipeline Inspection detai led report, May

1993. 0P-OO-UL-O01

ROV pipeline inspection 12" 5ales 1993 gas pipeline, Aug 1993, SS-14-RU-

005

324mm Sales Gas Line Pipeline 1993 Inspect ion summary report, Aug

1993, SP-14-UL-005

1994

1994

1994

1994

324mm Sales Gas Line 1993 Inspection findings - JPK stability and spanning analysis, SP-14-RL-

026

Pipeline Embedment survey report 12" sales Gas line and 12" infield

now line volume 1 and 2

12" Sales gas line and 12" infield now line investigations,SP-29·RL-

001

Positioning report Post cyclone Bobby, SP-KI-RC-019

Offshore Installation close out 1995 report 12" SGL pipeline stabilisation

vol 1,2,3, SP-14-RL-004

1995 1995 SGL Pipeline stabilisation

maintenance, SP·14-RL-018

Varanus Island

PL12 KP67.728:

Crossing Point 12"

Beach sales gas KP70 Varanus Island crossing pipeline

KP69.6

PL12

I KP 67.665:

90 degree

Beach bend,

KP70 Varanus Island Crossing Crossing Point 16"

KP69.746 Sales Gas

pipeline

'KP69.753

P69.753

~P69. 753

rp677

P67.2

KP63.7

I ~ ~ ,_._,,-,,-

Page 730f88

....

Subsea KP67.604: KP67.596: TPL13

90 degree Crossing bend Point 30"

Tanker loading line

KP67.1 : KP66.17: TPL8 Split sleeve

grouted Crossing clamp repair Point 30 "

due to Tanker 7degree loading line

bend

ROV inspection only. NoGP

readings taken

Summary of results and assessment of significant findings from ROV survey undertaken Aug 1993

analysis of identified areas following 1993 ROVsurvey

side scan sonar survey

Inspection of various locations of subsea seabed geology

P41 .367 Post cyclone positioning survey only

Survey of rock bolt locations

_1_' __ " _

OBJ 10: A53510

KP9.450'

KP9.45

KP9.450

KP]

KP16 ~-

Beach crossing KP.090

Beach Crossing KPO.060

Mainland

KPO.O

KPO.O: Flange

PO

PL17

KP99.6 Mainland

CS1

PL17

KP30.312 Mainland

CS1

KP31.

1 - KP31 1

J

1 KP17.927 -r' ROVsurvey

AEL Annual pipeline Inspection Post 1996 tropical cyclone Olivia, SP-14-RL-024,

June 1996

-- -

1996 AEL Sales Gas pipeline survey report, OOP-OO-UL-002, Jan 1996 tPo KP31'1 CP survey

fP67.3 KP3()

1996 AEL sales gas pipeline Geophysical pipeline survey via seismic and echo sounder

survey, SP-20-RL-007, July 1996

~P67. 1 clamp repair to

1996 12" sales gas pipeline survey KP67.1 bend due

bend due to Te Olivia, July/Aug 1996 to TC Olivia

I

996 AEL Sales Gas Line Diving survey, July KP67j GVI, NDT and CP inspection at 2 locations jKP40 1 1996

---- -

12" sales gas pipeline re stabilisation ~P67. 127

installation of additional KP24.830 1996 program interim report, SP-14-RL-028, pipeline anchors

Nov 1996.

-'f'/<P67.127 j

12" Sales Gas Line close out report , I close out report summarising action KP24.830 1996 SP20-RL-001, Nov 19996 taken following TC Olivia

12" Sales Gas pipeline Re stabilisation f'/<P67.127

anchor pull tests and installation, 1996 program, SP-20-RL-003.03, VOL I, II, III., following TC Olivia KP24.830 Nov 1996

Page 74 of 88 OBJ 10: A5351 0

1997 AEL Sales Gas line survey report, OP-OOI I ------ - ~ ------ -~------- Visual and fPO KP31 '1 RU-001 , Dec 1997 CP survey

Onshore Sales Gas Line Cathodic fi(PO KP31 .3t

1997 Protection survey, OP-OO-RU-002, Dec CPsurvey 1997.

12" and 16" Sales Gas Pipeline Mainland --Do KP3 section AS2885 Risk assessment, SP-21

RF-004, June 1998 1998

1998 12" and 16" Offshore section AS2885 risk assessment, SP-21-RF-003, Aug 1998

1998

L TS, Sinbab, Campbell and Compressor Station 1 Corrosion risk assessment and inspection scheme, HE-OO-MN-003, QCL

ref5015/1013, rev 1dated sept 1998

1999 shallow water Inspection report 1999 phase 1 and 2, Ref 9-TCR9954[1].001 ,

Tambouritha ConSUltants Pty Ltd

Assessment of the 1999 shallow water 1999 rov inspection Part 1, SS-00-RU-006, 4

April 2001 . QCL ref 5110/2035

~ ~ RA considers VI onshore section and subsea seclions of 12" and 16' SGL.

RA considers VI onshore, subsea and onshore mainland sections of 12" SGL

fP69.016 KP1B.976 1

12" SGL ROVand

CP

KP69.192 ... KP67.595

16" SGL RO.) andCP

1 A"b,~ r

Page 75 ot88 OBJ 10: A53510

I

2000 AEL 12" and 16" SGL route inspection, SP-14-RU-001 , June 2000

JP Kenny Shallow water p ipelines

2000 span assessment, JPK 01-OS04-01-P-7 008, SP-14-RL-032, June 2000

12" and 16" Sales Gas Pipelines, 4 2000 March 2000 CP potential survey,

F9001A02A, AUS R9133W001A

12" and 16" Sales Gas Pipelines, 28

2000 June 2000 Onshore Cathodic Potential survey, F 9031A001A, AUS

R9132K001A

12" and 16" Sales Gas Pipelines 3

2000 December 2000 DCVG survey, AUS A 9031

12" SGL Rock Anchor failure Review,

2001 SP-20-RG-009, JPK Ref 01/0S04/02JPI7I002, sept 2001

Onshore 12"/16" Sales Gas Pipeline

2002 Cathodic Protection survey June 2002 AUS1004

16" Sales Gas Pipeline 12" Sales Gas Pipeline

Page 76 of88

KP69.265 u """.- "".00 I t KP69.012

Assessment by jpk of 20 failed pipeline anchors on the subsea section of the 12" sales gas pipeline, identified in the OCL report line

OBJ 10: A53510

t KP10 KP31J

tKPO KP31 .31

t KPO KP31.3]

t 1 KP11.8 KP29.915

KPO KP31.3

t 1

Onshore 12"/16" Sales Gas Pipelines

2003 Cathodic Protection survey July 2003, AUS1046 R1046001A

2003 Shallow water inspection program RE-AEL-910-0401 , SS-C0-RU-027

Sales Gas pipeline Sacrificial Anode 2003 maintenance scope of work, June

2003, AUS1032

12" & 16" Sales Gas pipelines,

2004 wonnich and east spar pipelines, post cyclone Monty sidescan sonar

inspection survey, POODS

2004 12" Sales Gas pipeline September 2004 DCVG Survey AUSl154

Review of Apache Energy Pipelines

2004 2004, QCL REF 5226/2942, SP-14-RF-003.01/03

Sales Gas Pipelines Cathodic Protection survey August 2004 Field

data sheets, project AUSl153

Offshore Pipelines-Onshore section

2004 Cathodic Protection survey August 20040P-14-RU-003, Rl15201A.AUSl153

No inspection data available for onshore section on VI or the shore

zones at VI and the mainland.

t onshore VI j

Page 77 0(88

Approx KP67. 62 Approx KP15

t Limited CP readings taken on 16"(5) and I 1,"HI Vis and CP ;ns~ction via ROV

f""'''' Post cyclone Monty

""'''·'1 KP66.5 positioning and SSS survey KP13.5

(12") (12 ')

t t

OBJ 10: A53510

KPO KP?

i 1

f Sacrificial anode

replacement scope of work.

t t DCVG survey of 2 areas of interest in tidal flats

area downstream of KPO

No inspection data available for tl1e onshore section on VI or the shore

zones at VI and the mainland

I

u

Subsoil pipe coating repair 17-10-04 i 2004

(P.Beckford report) KPO.O Repair to coating damage on 12" and 16" Sales Gas pipelines

Sales Gas Pipeline Cathodic Protection I r I 1 2004 Sacrificial anode testing 13-11-04, AUSl172, L 117201A KP20.21

KP12.112 2IKP29. 050

12" Sales Gas

Pipeline KP69.7 KP68.243

VI Ultra Shallow water and onshore

2004 pipeline inspection, RE-AEL-916-01 Rev 2, OP-14-RU-002, inspection performed

Oct 2004

f i GVI only for 12"

- tP1.95

-KP31 ' j

2005 December 2005 CP survey,

AUS129901A I

2005 Annual Summary report of 1 2005 Inspection and corrosion management Report summarises inspection and corrosion

activities AE-00-RN-004 management activities for all assets, including 12''/16''

I I sales gas pipelines, onshore and offshore sections, during the period 200312004, and up to may 2005.

I i f f Fugro Report for the post Cydone ROV

I 2006 inspection, SS-OO-RU-038(1), 10th -19th

April 2006 16" KP67.5 16" KP62.915 12" KP51 .330

rea:ngs i i

2006 VI Offshore pipework monitoring18/6/06 I

Onshore 12"/16" sales Gas pipelines I KPO KP31.3 i

2006 onshore section Cathodic Protection t j survey July/Oct 2006 AUS R137101A

I . __ . - - _ .. .~ ~

Page 78 0(88 OBJ /0 : A53510

I

2007 Sales Gas Pipelines - 5 year integrity review SP-14-RL-067, 30 May 2007. Applicable to 12" and 16" sales gas pipelines

I I

!

2007 PL 12 Varanus Island Validation summary report (Lloyds report) AE-14-RL- t i

003 REVA May 2007. I I

Applicable to VI PL 12 I I

license area only

2007 12"/16" SGL Onshore section cathodic protection annual survey R151701 , ro -~311 August 2007

KP10.25 KP31"}

2007 12"/16" Onshore section DCVG coating survey , R151801, August 2007

CP readings

1 : : .

I

2007 VI Offshore pipework monitoring 1/8/07 taken onshore VI

CP and GVI, I 2007 2007 Onshore pipeline Inspection workbook, sept 2007 all pipelines

onshore VI

I

Moduspec Review of recommendations from 2004 pipeline risk assessments, 10-4-2007, PAU0060.1

2007 Moduspec Gap analysis of the QCL review of the AEL pipelines(2004) with the

requirements of AS2885 and the Petroleum submerged Lands Pipeline Regulations, PAU0060.18, SP-14-RG-040 Review Applicable to all AEL pipelines

- ~

CP readings

2008 VI offshore pipework monitoring MCC building 2008 laken onshore VI

---_.- --- -------- --_. _.- --- ---___ I

Page 79 of 88 OBJ 10: A53510

Attachment 8 (pages 80 - 87) Table 2 - Prescriptive Requirements

1992 1993 1994 1995 1996 1997 1998 1999

36A Work Practices: a licensee shall operate the pipeline specified in the licence of which he is the

registered holder in a proper and workmanlike manner, and shall secure the safety health and welfare of

Petroleum applicable onshore VI persons engaged in operations in connection with

Pipelines Act and onshore mainland

1969 sections

38(b) A licensee shall maintain the pipeline in good condition and repair

Petroleum 97(3) Work Practices: a licensee shall operate the

Submerged applicable state waters pipeline in a proper and workmanlike manner, and shall

sections secure the safety health and welfare of persons engaged Lands act 1982 in operations in connection with the pipeline

, P9: "ftIe1ieeesee stIaII iIaIIe _10 Iriwe I'3Iied ... a ~." .. .....,....--...... atillefwlll;

1ftS t..iraw;e ~"","""' ..•. .a~dtllel9Sllls oIea1111~,",e.J1 I Pir ..wily a

(12'" ~u.-ce ~~ eI\!jiIIeeI,lIId lie SIItIsetl,elll

Sales Gas ......... PSt.A

~~ C - lIeR"'" -- -----

~ Pt3: I:1I'IIe$S CIIIiIeIwise ~.Ii»j "I/iIeeIfIF,1IIe tcenseeslllllf ~QIIt ... __ ....... ~"

~eoIleAIaI ...... elIIteInaI AMuaI eJIteMat -'fIIpeIiIIe ___ ~_ ...... "'" resuIIs !'"'"""- ~- ~~1'UfIIeY ,... e-.SPNey ............ -of tile $¥"ElY ... be IGfISed vi1118le • ..-aM sIlaII , SWoIe!I/ ..va)' """"" ~

iRdtMIe an engifIeeIio:Ig .~ ell , - .- ..... . .. -.- --- .-- -- .- ---- - ~--. ---

l-. __ _ ~-_ _ _ -~

i.....-.-_______ ~ ~~-----' ~-...........-- -.~ - -- - --- .- , " _ _ _ _ '.0 _ • • __ •• __ - - - . -----------

Page BO ofBB OBJ 10: A53510

PL 12 P7: the licensee shall be responsible for installing and monitoring the cathodic protection test pOints

PL 12 P7: the licensee shall. when required. submit to PL 12, issued UNDER the director a report in writing outlining the results of the

PPA 69 ·9/5/85 corrosion surveys and the details of any resulting action by the licensee

PL 12 P7: the licensee shall carry out an annual external survey of the pipe~ne after the cyclone season and the annual extemal annual extemal annual extemal annual external

annual external survey annual external survey annual external survey resutts of the survey shall be submitted to the director in survey survey survey survey

writing - -

the licensee shall be responsible for installing and monitoring the cathodic protection test points

PL12 Variation 1/91· the licensee shall. when required. submit to the direclor 2, issued 11/5192 (12" a report in writing ouUining the results of the corrosion Sales Gas Pipeline· surveys and the details of any resulting action by the

consistent with licensee TPL8)

the licensee shall carry out an annual external survey of annual external annual external annual external annual external

the pipeline after the cyclone season and the results of annual external survey annual external'survey annual extemal survey the survey shaR be submitted to the director in writing

survey survey survey survey

PL12 and The licensee shall maintain and monitor a

variations system. acceptable to the director. for the < monitoring and control of corrosion and stress

(Varanus Island) corrosion

the licensee shall. when required. submit to the director a report in writing oullining the

, results of the corrosion surveys and the details of any resulting action by the licensee

~ the licensee shall. within 3 months of the date of commencement of operation of the pipeline.

PL 12 Variation 9P/97 have cause to have carried out an inspection

8 (16" Sales Gas of the pipelines cathodic potential and voltage

Pipeline-consistent gradient using the close order potential survey

w ith TPL 13) issued techniques. and ther

30/9/98 - . ~ ~ ~~

not more than 2 yearS after tfie grant Of this licence .. .. .. ... an'd at intervals of n'Ot more than five years' tfiereafier ... .. .. . ... carry OUt a review to aetennine ti1e likely' eontinuea integritY of the pipeline. The licensee shall within 60

days 01 finisning this review

The licensee shail carry out an extemal surVey Cif the pipeline route after each malor storm

activity in order to monitor the integrity of the pipeline

Page 81 or 88 OBJ 10: A53510

- - -

~

-Pipeline IMM

Requirements as I

per section 8 of theAEL document issued for

Underwater use 5/8/05 I

Inspection Manual AE·OO·MG

,

005 I

~

- Annual inspection IMM requirements frequency to be applied,

onshore pipeline applicable for onshore as per AS2885.3 1997,

Annual topographical until the risk based

inspection VI and mainland approach introduced in Annual topographical survey in beach zone,

survey in beach zone,

manual AEL doc sections of 12"/16" AS2885.3 2001 , is annual GVI , annual CP, annual line walk,

annual GVI , annual CP,

OP·14·MG·001 , pipeline, between

adopted. Annual annual surge protection system/static earth annual line walk, annual

landfall and the topographical survey in system inspection.

surge protection

Rev 4, 22/3/06. pipeline termination/pig beach zone, annual GVI,

system/static earth

(originally issued launcher/receiver. annual CP, annual line

system inspection .

27/6/97) walk, annual surge protection system/sta

AS2018·1981 SAA 12" SGPL installed after this standard was superseded

Liquid petroleum applicable to PL 12 by AS2885-1987, therefore the applicability of this

pipeline code standard to the 12" SGPL is irrelevant

I ,

Section 6.9.3.3(a)Buried pipeline: (i) potential surveys !

shall be made at intervals of not more than 12 months, i or where cathodic protection potentials may be affected CP survey CP survey CP survey CP survey CP survey CP survey CP survey

AS2885·1987 AS2885-1987 by stray DC currents, potential survey intervals shall be

approved . (iii) galvanic ano Pipelines · Gas Pipelines- Gas and

and liquid liquid Petroleum (the

SAA Code); applicable Petroleum (the to TPL8(12" SGPL),

SAA Code) TPL 13(16"SGPL), Section 6.9.3.3(b) Submerged Pipeline: the efficacy of a galvanic anode cathodic protection installation shall be initial post

--- A..d~hli~hAd within ~ nArinn of not .morA th~n 1? mnnth" _in~t;:al~tinn r.p r.p SJJrvAV -

AS2885.3 - 2001 Pipelines - Gas

and liquid Petroleum Pt 3 Operation and Maintenance

Offshore Standard DNV­

OSF-101 Submarine

Pipeline Systems 2000

Onshore pipeline inspection manual op·

14-MG.()01 . section 2.1. states that the

standard provides the justification for

implementing the inspection system.

2000

f en 0 0 J N

J f

CO 0 0 I N

J I

l"-0 0 I N

J (

<0 0 0 I N

J

I It) 0 0 I N

)

I ~ 0 0 I N

J I .

C") 0 0 I N

i I

N 0 0 I N

J

.... I 0 0 N

J

! 0 0 0 I N

J

annual exlernal survey annual external survey annual exlemal survey annual external survey annual external survey annual external survey annual external survey annual external survey annual external survey annual external survey

annual external survey annual exlernal survey annual external survey annual external survey annual external survey annual external survey annual external survey annual external survey annual eXlernal survey annual external survey

Integrity review Integrity review

I

Page 85 of88 OBJ 10: A53510

level 1 surveys(side scan sonar): side scan sonar survey

at least every 3 years.

-level II surveys (ROV CP and

ROV CP and GVI GVI): every 3 years

-level III surveys: shall be carried

out following the discovery of suspect defect areas on the pipeline

I either at the same time as the main surveyor as soon as possible after

the defect has been found

I I

I i level IV surveys(inspection by diver, lntelligent pig inspection):

level IV surveys by IP shall be carried out at a frequency based on

: the condition of the pipeline, current knowledge of its condition, and the rate of deterioration of the pipeline. ,

Thema

- - '.

Annual topographical Annual topographical Annual topographical Annual topographical Annua l topographical Annual topographical Annual topographical

Annua l topographical survey in beach zone, Annual topographical survey in beach survey in beach zone. survey in beach zone. survey in beach zone. Annual topographical survey in survey in beach zone, survey in beach zone. survey in beach zone, survey in beach zone.

annual GVI, annual CPo annual line walk, zone, annual GVI, annual CPo annual annual GVI, annual CP, annual GVI, annual CP, annual GVI, annual CP, beach zone, annual GVI , annual annual GVI , annual CP, annual GVI, annual CP, annual GVI, annual CP, annual GVI . annual CPo

annual surge protection system/static earth line walk . annual surge protection annual line walk , annual annual line walk. annual annual line walk, annual CP, annual line walk, annual surge annual line walk. annual annual line walk. annual annual line walk, annual annual line walk, annual

system inspection. system/static earth system inspection, surge protection surge protection surge protection protection system/static earth surge protection surge protection surge protection surge protection

system/static earth system/static earth system/static earth system inspection. system/static earth systemfstatic earth system/static earth system/static earth system inspection. system inspection. system inspection. system inspection. system inspection. system inspection. system inspeclion.

CP survey CP survey CP survey CP survey CP survey CP survey CP survey CP survey CP sU/vey CP survey

CP survey CP survey

-- ------

Page 86 of88 OBJ 10: A53510

Operation Inspection and Repair: Section 10 Inspection and monitoring philosophy,

ASOO: an inspection and monitoring philosophy shall be establ ished, and this shall form the

basis for the detailed inspection and monitoring program. The philosophy shall b

Operation Inspection and Repair: Section 106 Pipeline Configuration Survey. 8202: a

long term inspection program shall be established reflecting the overall safety objective for the pipeline, and shall be mainta ined/updated on a regular basis

Operation Inspection and Repair. Section 108 Pipeline Configuration Survey: 6209:

critical sections of the pipeline system vulnerable to damage or subject to major

changes in seabed conditions ie support andlor burial of the pipeline, shall be inspected

Operation Inspection and Repair: Section 10C Inspection and Monitoring of external corrosion. C304: A survey of the corrosion

protection system should be carried out within 1 year of installation

Operation Inspection and repair Section 10D Inspection and Monitoring of internal

corrosion, D204: The frequency of internal inspections shall be determined based on factors such as cri ticality of the pipeline, potential corrosivity of the fluid, detectio

Inspection as required at a frequency determined by risk assessment. This to be detailed in Safety and Operating

Plan. Inspection frequency to be based on past reliability of the pipeline, historical records, current knowledge 0

its condition, the rate

Page 87 of88 OBJ 10: A53510

Attachment 9 - Event Analysis Chart

Pipeline constructed and commissioned

Pipeline anti­corrosion coating

failurddamage at VI beach crossing

Extemal visual inspections

..

Sections.

inspection and monitoring

Causal Factor

Cathodic protection installed

Pipeline inspected and

monitored

Surveys oCVI beach crossing/shallow

water section carried

Ineffective CP inspection freQuency

CP inspection and monitoring

Page 880(88

Location specific problems not taken

into account

Pipeline maintenance and repair

Post inspection repairs not always

carried out

Pipeline in stcady mode

operat ion

Reduced pipeline wall thickness at beach crossin!.!

Positive assessments

(rcoons)

inencetive arrangements for rcvicwine. rCDarts

Usc of specialist contractors

12"& 16" lines isolated

at CSI

Helicopter retums to VI

OSJ 10: A53510

lIe1icopter depans for CS I

Evacuation of non essential

personnel

Muster ESD initiated (2 locations) completed

ERT deployed to assess

Boat depans for Il arriet A

Boat rctums toVI

Helicopter & boat sent to observe

Tank A isolated

manually

Fires oul