60. WWF-Harvey Report Final Draft 6 May 2010

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PO Box 771026Eagle River, Alaska 99577

Recommendations forAustralian GovernmentCommission of Inquiry

Montara Wellhead PlatformUncontrolled Hydrocarbon Release

Report to:

World Wide Fund-Australia (WWF) Montara Oil Spill – Drilling and Well Control Issues

Reference No: 122304

Prepared by:

Oil & Gas, Environmental, Regulatory Compliance, and Training

June 2, 2010



Montara Oil Spill – WWF Input to Australian Government Commission of Inquiry of 137

1. Executive Summary …...……………………………………………………………… 4

2. Introduction …..……………………………………………………………………...... 19

3. Incident Summary…………………………………………………………………….. 19

4. Findings and Recommendations………………………….. …………………............ 22

4.1 Montara G1, H2, and H4 Well Integrity – Immediate Well Control Intervention Needed ………. 23

4.2 Live Wells Require Safe Handling ………………………………………………………………… 27

4.3 Wellbore Gas Bubbling Requires Immediate Attention …………………………………………… 29

4.4 Surface Well Control Installation Before Barrier Removal ……………………………………….. 32

4.5 Simultaneous Well Control Operations Should Not Be Conducted by the Same Rig and Crew …. 32

4.6 PCCC Should Have Been Replaced ……………………………………………………………….. 34

4.7 Secure Wells During Rig Moves …………………………………………………………………... 36

4.8 Batch Drilling Increases Risk ……………………………………………………………………… 36

4.9 Temporary One-Barrier Systems Are Not Good Oilfield Practice ………………………………… 40

4.10 Two-Barrier Systems Are Good Oilfield Practice …………………………………………………. 43

4.11 MLS Corrosion Control ……………………………………………………………………………. 53

4.12 Approved Barrier List ……………………………………………………………………………… 54

4.13 Barrier Installation and Removal Training ………………………………………………………... 56

4.14 Corrosion of 13-3/8” MLS Threads ……………………………………………………………….. 56

4.15 Casing Design ……………………………………………………………………………………… 59

4.16 BOP Parking Lots ………………………………………………………………………………….. 61

4.17 Blowout Preventer (BOP) and Wellhead Control Requirements ………………………………….. 62

4.18 Vendor Equipment Compatibility…………………………………………………………………... 63

4.19 Float Collar Return Valve Failure ………………………………………………………………….. 64

4.20 Failure to Comply with H1 Well Suspension Permit Conditions ………………………………….. 68

4.21 Common Cement Failures …………………………………………………………………………... 71

4.22 Cementing High Angle Wells ………………………………………………………………………. 71

4.23 Cementing the Hydrocarbon Zone ………………………………………………………………….. 724.24 Cement Overdisplacement “Wet Shoe” …………………………………………………………….. 75

4.25 Cement Evaluation ………………………………………………………………………………….. 75

4.26 Cement Grade ………………………………………………………………………………………. 79

4.27 Offline Activity Management & Tracking …………………………………………………………. 80

4.28 Topside Installation Delay Increased Risk …………………………………………………………. 82

4.29 Drilling Delay Should Have Been Considered for Risk Mitigation ………………………………... 88




4.30 Safety Case Review Did Not Identify or Mitigate Wellhead Control System Risks ………………. 88

4.31 H1 Cost Savings …………………………………………………………………………………….. 91

4.32 Minimum Health, Safety & Environmental Regulatory Standards ………………………………… 95

4.33 Pre-Drill Risk and Impact Assessment ………………………………………………………………104

4.34 Contractor Responsibility …………………………………………………………………………… 1054.35 Inspections and Audits ……………………………………………………………………………… 108

4.36 Emergency Pre-Planning and Relief Wells ………………………………………………………… 111

4.37 Lack of Engineering and Technical Resources …………………………………………………….. 114

4.38 Operator and Contractor - Training and Qualifications ……………………………………………. 116

4.39 Agency Decision Making and Oversight ………………………………………………………….. 118

4.40 Agency Coordination ………………………………………………………………………………. 132

4.41 Agency - Training and Qualifications ……………………………………………………………… 133




1. Executive Summary

This analysis responds to a request by World Wide Fund for Nature–Australia (WWF) for a review of allthe materials that were submitted to the Australian Government in regards to the Commission of Inquiry

for the Montara Wellhead Platform Uncontrolled Hydrocarbon Release.This analysis concludes that:

Montara G1, H2, and H4 Well Integrity – Immediate Well Control Intervention Needed

1.1 Of urgent and primary concern is the existing safety status of all the other wells on the MontaraWellhead Platform. While H1 is now, reportedly, secure, with a two-barrier system in place, threeother wells on the platform (GI, H2, and H4) are not secure. GI, H2 and H4 well integrity issueswarrant immediate attention.

1.2 Batch drilling programs, by nature, are subject to repetitive flaws. Flaws encountered on H1 wererepeated in the other wells, and this warrants immediate action and intervention to secure these

wells and prevent another well control problems.1.3 The GI well gas leak was not identified as a serious well integrity problem, which it should have

been. Immediate intervention was warranted when the gas bubbling problem was found.

1.4 Of urgent and primary concern is whether similar well safety concerns could exist on otheroffshore platforms, especially those owned and operated by PTTEP.

1.5 Good oilfield practice includes verifying actual cement placement depths in the well and cementbond integrity prior to removing the BOP and moving the rig off the well. This was not done inany of the Montara wells.

Live Wells Require Safe Handling

1.6 The complexity of the H1 well and the mere fact that it penetrated a pressured hydrocarbon zonecontaining oil and gas should have warranted PTTEP and Atlas Drilling to treat this well as a“live” well, with the potential for hydrocarbon flow. The need for pressure barriers to be installedto “safe-out” the well while it was suspended, and the need to set a BOP as part of the re-entryprocess, should have been standard well control procedure.

1.7 The BOP should not be removed until at least two independent, pressure tested barriers areinstalled in the well. Both barriers should remain in the well until well control is establishedeither by replacing the BOP or connecting to a wellhead control system. It is not good oilfieldpractice to leave only one barrier in place, even for a temporary period of time.

1.8 Installation of only a single well barrier is not good oilfield practice for wells where the

intermediate casing shoe is set 3m (10’) above the water-oil contact and the casing string is setthrough 1,187m (3,894’) of hydrocarbon zone.

1.9 Wells drilled into hydrocarbon reservoirs must be treated as live wells with the potential to flowhydrocarbons to the surface, unless engineering studies demonstrate the well is not capable of unassisted flow to the surface.




Wellbore Gas Bubbling Requires Immediate Attention

1.10 Three major danger warning signs were ignored: (1) a failed float, (2) a poor cement job, and then(3) gas bubbles were detected when the PCCC was removed. The seriousness of gas bubbling iscompounded when it is correlated with a failed float valve and poor cement job, because thisindicates the likelihood of gas percolating through the failed cement job.

1.11 Wellbore gas bubbling is direct evidence of gas influx, which is a very serious well safety issuethat requires immediate hazard assessment and intervention.

1.12 H1 has been plugged and secured by Alert Well Control; however, GI has not. Immediateattention should be given to well GI to address annular gas communication issues and future safewell re-entry plans.

Surface Well Control Installation Before Barrier Removal

1.13 Regulations should require BOPs or wellhead control systems to be in place prior to removingwell barriers. PCCCs should be set and pulled through a BOP or wellhead, maintaining

continuous well control throughout the procedure.

Simultaneous Well Control Operations Should Not Be Conducted By the Same Rig and Crew

1.14 The West Atlas rig should have been left over H1 until the well was properly secured. The factthat the West Atlas was working on H4 when the blowout started on H1 delayed emergencyresponse actions and limited response options.

1.15 The West Atlas rig and crew should not have left H1 uncapped, unattended, and without twopressure-tested well control barriers in place. Simultaneous high risk operations should not beconducted by the same drilling crew.

PCCC Should Have Been Replaced

1.16 The 9-5/8” PCCC should have been immediately replaced in H1 after the 13-3/8” casing threadswere brushed.

Secure Wells During Rig Moves

1.17 Producing wells should be properly and safely secured, and pressure should be isolated, prior tomoving a rig from one well to another on an offshore platform.

Batch Drilling Increases Risk

1.18 Increased risk associated with batch drilling and tie-in operations was not examined or mitigatedby the DA or NOPSA.

1.19 The new batch drilling program, when compared to the original top-to-bottom drilling program,substantially increased the number of rig moves and wellbore interventions. Each rig move andwellbore intervention increases risk.

1.20 While batch drilling operations are conducted worldwide, they are not common. Batch drillingoperations, if carefully planned and executed, can be completed safely, however, the increased




risk associated with batch drilling must be addressed and mitigated. Good oilfield practicerequires each well to be properly secured prior to moving to the next well.

1.21 Batch drilling improves drilling efficiency, equipment handling, and logistics, saving time andmoney on expensive offshore drilling operations. Yet, this exposes the program to many rigmoves and additional well suspension procedures, creating an elevated level of risk.

1.22 It is not good oilfield practice to continue batch drilling operations if any well control or wellintegrity issues are found.

1.23 A more conservative approach is to drill each well from start to finish, using an uninterruptedBOP control system. In this case, well control would be transferred from the BOP stack to thewellhead control systems at the final tie in.

1.24 Well control regulations should include a requirement similar to Norway’s PSA Well BarrierRegulation that requires sole focus on restoring well control barriers when any barrier integrityissue is found. “If a barrier fails, no other activities shall take place in the well than thoseintended to restore the barrier. When the wells are handed over, the status of the barriers shall betested, verified and documented.”

Temporary One-Barrier Systems Are Not Good Oilfield Practice

1.25 Throughout the Inquiry process PTTEP maintained it is good oilfield practice totemporarily leave a well open to atmosphere for a period of days with only one barrier.This position is not supported by PTTEP’s own well construction standards, internationalregulation, or industry standards for what constitutes good oilfield practice.

1.26 The 9-5/8” PCCC should not have been removed, leaving a single barrier in H1. There was noreason that the 9-5/8” PCCC had to be removed on August 20, 2010. The 9-5/8” PCCC shouldhave remained in H1 while a technically robust and safe plan was developed to clean the 13-3/8”MLS threads. This did not require rig work to cease; the rig could have proceeded to otherMontara well tie-ins while PTTEP’s engineering and safety team devised a solution.

1.27 Permit approval based on removal of secondary and tertiary barriers (even if only temporary) isinconsistent with the DA’s reported three barrier standard. Continuous, not intermittent, wellcontrol is needed.

Two-Barrier Systems Are Good Oilfield Practice

1.28 The seriousness of the H1 well configuration on August 20, 2009 cannot be understated. No wellshould be left open to atmosphere, without surface well control, and redundant, multiple pressureisolation and/or barrier systems in place.

1.29 Prior to 2004, Australia relied on the minimum engineering standards listed in The Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production. If these standards

were used to decision H1’s well suspension application the DA would have required a series of cement plugs in the casing, meeting a minimum “two-barrier” industry well control standard,likely averting this incident.

1.30 Written guidance should have been issued to DA staff to define what a “good oil field practice” isin terms of well control barrier. Other international governments do not leave an issue soimportant as well control barriers to individual staff discretion and interpretation.




1.31 A review of minimum regulatory standards from Norway, Canada, the USA, and Australia’sstandards in place prior to 2004, plainly show that a two-barrier system for well control is goodoilfield practice. H1 was not suspended using good oilfield practice.

1.32 If the prescriptive Australian standard at § 514 was still in place as a minimum standard, a seriesof cement plugs would have been installed in the well, averting disaster.

1.33 If the prescriptive Australian standard at § 515 was still in place, as a minimum standard, wellcontrol would have been required at the surface as part of the well re-entry procedure.

1.34 Other Australian DA’s agree that at least minimum two barrier well control system is “goodoilfield practice” and some recommend even three barriers for long-term well suspensions.

1.35 It is not good oilfield practice to remove barriers before a production tree or BOP is installed. Thebarriers should remain in place until the production tree or BOP are in place, establishing wellcontrol.

1.36 It is good oilfield practice to document barriers installation and removal.

MLS Corrosion Control

1.37 PCCCs are not an adequate replacement for a shallow-set cement plug barrier, unless the PCCC ispressure rated for the maximum well pressure, is properly set and tested, and can be set andremoved through a BOP.

1.38 When the H1 well tie-in plan was revised to use a 9-5/8” PCCC to replace a cement plug, the DAshould have required a BOP to be set and the PCCC to be pulled through the BOP to maintaincontinuous well control, and should have required the Operator to demonstrate that the staff weretrained, qualified and experienced to use this equipment.

Approved Barrier List

1.39 A list of approved barriers should be established in regulation and that list should be updated on a

routine basis to incorporate new technology as it is developed. 1.40 Good oilfield practice is to develop a final as-built engineering drawing of the completed well to

accurately document all subsurface well construction equipment, piping and cement locations. Acompleted, accurate well file should be maintained by the onshore drilling engineer. This servesas a reference for engineers who may later design well completion or well workover projects.

Barrier Installation and Removal Training

1.41 Minimum training and qualification standards should be set for well control barrier installationand removal. There should be a system in place to document barrier installation to ensure it wascompleted.

Corrosion of 13-3/8” MLS Threads

1.42 Corrosion caps should be installed to prevent corrosion. Installation should be verified anddocumented as complete before the well is suspended. Government officials should inspect andaudit barrier installation, testing and removal.

1.43 Video and/or cameras should have been run to photograph 13-3/8” MLS thread corrosion/scalingconcerns and transmitted to the onshore engineering team for further assessment. Instead, a series




of dangerous well control decisions, resulting a catastrophic blowout, were triggered by thissingle piece of unconfirmed data.

1.44 Safety and risk assessment reviews must be conducted to evaluate the safest and lowest risk options for complex well interventions that involve alteration of primary well control barriers.

1.45 Data that has major influence on subsequent well control decisions must be confirmed byquantitative assessment and be examined by health, safety, environment and engineeringspecialists before a decision is made on major changes in well control barrier configuration orremoval timing. Alternative solutions should be thoroughly evaluated.

1.46 Vetco Gray should reevaluate its MLS design and thread cleaning protocol to incorporate the H1well blowout lessons learned. Either the 9-5/8” MLS hanger needs to be designed with a deeperset to provide clearance between the outside diameter of the 9-5/8” PCCC and the inside diameterof the 13-3/8” MLS threads, or a brush tool needs be developed to clean the threads within theexisting clearance. Other MLS vendors may have a similar need to evaluate this same problem.

1.47 Vendors should be consulted regarding manufacturer recommendations on how to addressengineering and operational issues associated with their equipment, especially when rig staff isnot familiar with the equipment.

Casing Design

1.48 The H1 casing design inherently created a high level of risk because it set a single string of intermediate casing at a high angle across a known thief zone and into a high pressurehydrocarbon bearing zone to a depth of 3,796m (12,454’). Multiple strings of intermediate casingshould have been set to isolate lost circulation zones and seal off anomalous pressure zones.

1.49 Regulatory standards need to be clear about intermediate casing depth, the required number of intermediate strings, and cementing and pressure testing criteria. Intermediate casing serves theimportant function of sealing off anomalous pressure zones, lost circulation zones, and otherdrilling hazards. If intermediate casing is set in the production zone, it must be treated asproduction casing and held to the same standards.

BOP Parking Lots

1.50 Well H1 should not have used as a BOP parking lot. This resulted in not setting a 13-3/8 PCCC.Not only was a 13-3/8 PCCC required in the H1 well suspension plan approved by the, but wasalso needed to secure the 9-5/8” x 13-3/8” annulus.

Blowout Preventer (BOP) and Wellhead Control Requirements

1.51 A BOP should have been set for H1 re-entry because: the well had already been drilled through1,187m (3,894’) of the hydrocarbon interval; the well had known cement integrity issues; the wellhad no additional cement plugs set in the casing; and the well had no other surface well controlinstalled. H1 was a “live” production well, warranting a BOP stack to be set for well re-entry.

1.52 Regulations need to include unequivocal BOP and wellhead control standards. The standardsshould specify when BOPs and/or wellhead control systems must be in place and when they canbe removed.

1.53 Well control manuals and instructions need to address blowout control during drilling,completion and all well re-entry operations including well tie-ins. Most well control manuals andtraining focus on well control (BOP and mud systems) while drilling and do not allocate




sufficient technical guidance for rig staff on well control during batch drilling, well tie-ins andwell workovers. More instruction on these points is needed .

1.54 Government inspectors are needed to witness and verify BOP testing.

Vendor Equipment Compatibility 1.55 Minimum standards should be set that require a through technical review of vendor equipment

compatibility as part of the well construction design.

Float Collar Return Valve Failure

1.56 The H1 daily drilling and cementing report clearly showed a failed float collar return valve, a wetshoe, improperly calculated cement volumes and no cement integrity verification. PTTEPManagement, and the DA reviewed these reports and took no action to address the H1 cementintegrity issues.

1.57 A properly cemented shoe track should be filled with cement, creating a solid cement plug at the

base of the well to prevent hydrocarbon entry into the well. If the casing shoe track is notproperly cemented, it creates a pathway for hydrocarbons to enter the well.

1.58 A mechanical bridge plug should have been set above the cement shoe to temporarily provide aprimary barrier in the well. The primary barrier should have been coupled with a shallow-set plugin the 9-5/8” casing to create a two barrier well control system.

1.59 A failed float collar return valve can result in insufficient annular cement volumes. Annularcement integrity should be evaluated with cement evaluation tools, and if cement integrity iscalled into question, a cement squeeze should be performed to ensure there is no pathway forhydrocarbons to move to the surface via the wellbore annulus.

1.60 Float collar return valves commonly fail, and because of this, it is good oilfield practice andstandard procedure worldwide to check to see if the float valve holds.

1.61 Industry well construction plans should provide detailed instructions on how to handle a floatcollar return valve failure.

1.62 Failed float collars are a known risk in the oil field and can result in a compromised cement job. Itis such a well-known risk that every well plan has a requirement to “check floats” to ensure theyare holding. Any indication of a compromised cement shoes should trigger the installation of additional well suspension barriers, because a compromised cement shoe cannot be relied upon asa barrier. A compromised cement job is also suspect in the 2010 USA Gulf of Mexico Macondowell blowout.

1.63 A failed float collar valve is a clear indication that a cementing integrity problem occurred.Unless steps were taken to remedy the cement job, and then verify the effectiveness of the

remedial actions by additional evaluation tools, the integrity of the casing shoe cement plug at thebase of H1 should have remained a concern, and a documented risk factor, for this well.

1.64 Government tracking and analysis of offshore cementing failure statistics to assess cement failuretrends and successes with best available technology would assist permit approval officers,compliance officers and policymakers by providing them with the technical information neededto make informed decisions.




Failure to Comply with H1 Well Suspension Permit Conditions

1.65 The H1 13-3/8” PCCC was not install, in violation of the H1 permit and prompting a series of actions that ultimately led to the blowout.

1.66

Industry self-audits and government physical inspections and paperwork audits are needed on aroutine basis to ensure wells are constructed in accordance with permit stipulations.

1.67 Government oversight (via inspections and audits) is needed to verify compliance with permitconditions.

Failure to Comply with H1 Well Suspension Permit Conditions

1.68 The H1 13-3/8” PCCC was not install, in violation of the H1 permit and prompting a series of actions that ultimately led to the blowout.

Common Cement Failures

1.69 Regulatory standards should be established to ensure there is: (1) adequate cement in the annulus,(2) the casing shoe is properly cemented (or additional barriers are set to account for a failedcasing shoe), and (3) high pressure, hydrocarbon and thief zones are isolated.

Cementing High Angle Wells

1.70 High angle sections of casing are notoriously difficult to cement. High angle casing strings oftenrequire additional remedial cementing treatment, careful evaluation, and intervention if a cementseal is not initially obtained.

1.71 Because cement plugs placed in high angle sections of casing are notoriously difficult to cement,

a three barrier system should be required for this type of system, setting two additional plugsabove the high angle well section to ensure well control.

Cementing the Hydrocarbon Zone

1.72 Cement volume calculations must be based on accurate as-built casing depths and caliper data,and must be subject to QA/QC by the drilling engineer assigned to the project. The Operator andgovernment officials should QA/QC and audit cementing installation.

1.73 Errors in the cement volume calculation occurred because PTTEP drilled the well deeper and thecement volume was not recalculated to correspond to the new depth.

1.74 Cement should have been placed 69m above the top of the reservoir, but it ended up 61m below

the top of the reservoir. This left a 130m gap in cement in the annulus at the top of thehydrocarbon reservoir.

1.75 This left a 91m gap of cement was created in 9-5/8” x 13-3/8” annulus.

1.76 Good oilfield practice includes placing cement in the annulus across lost circulation zones,verifying actual cement placement depths in the well and cement bond integrity prior to removingthe BOP and moving the rig off the well.




Topside Installation Delay Increased Risk

1.90 Major, late changes in the Montara Platform Topside Module installation schedule, well design,wellhead control tie-in plans and procedures contributed to hastily revised engineering and safetydesign plans and was a significant contributing factor to the well blowout.

1.91 Technical review of well completion plans, temporary well suspension plans, and re-entryprocedures was hurried, incomplete, and absent of safety and environment agency peer review.

1.92 NOPSA’s Safety Case review did not identify the fact that the increase in rig moves needed tocomplete a batch drilling and completion program increased risk to the topside facility and thesafety of rig personnel (for which NOPSA has clear responsibility). Despite recommendationsthat NOPSA officials be questioned on this and other points, no one from NOPSA was called totestify.

1.93 Agencies assigned to carry out oversight responsibilities should have mutual professional andtechnical respect for one another. Agencies should effectively communicate and call on eachother to provide technical assistance and peer-review and conduct multi-agency review processesthat bridge potential “gaps” between regulatory jurisdictions. Lack of agency coordinationmaterially contributed to the incident.

1.94 The Montara Platform Topside Module installation delay should have triggered a multi-agencysafety and environmental assessment to examine the potential risks associated with the newlyproposed batch drilling program and new Topside Module installation plans. The inability toimmediately tie newly drilled wells in to the platform wellhead control system significantlyincreased the risk factor for the Montara wells. The lack of a coordinated, peer-reviewedtechnical, safety, and environmental assessment to evaluate and identify the risks of this majordesign change appears to have contributed to the incident.

1.95 An analysis should have been completed to evaluate the increased risk associated with major latechanges to the well drilling and tie-in plans and top-side installation delay. This work was notcompleted.

Drilling Delay Should Have Been Considered for Risk Mitigation

1.96 NOPSA and the DA should have considered delaying the drilling program until the TopsideModule was available or have required additional risk mitigation.

Safety Case Review Did Not Identify or Mitigate Wellhead Control System Risks

1.97 The November 2008 West Atlas Drilling Rig Safety Case Revision included information on thebarrier and well control risks, yet that analysis was incomplete because the Montara DrillingProgram was not yet completed. And NOPSA who is responsible for reviewing the SCR,

acknowledged its lack of downhole expertise to the Commission, but did not enlist any technicalreview of the SCR from the DA or independent consultants on the barrier and well control risksidentified in the preliminary plan.

1.98 The November 2008 Safety Case Revision (SCR) should not have been approved by NOPSA,absent well plans for the Montara wells drilled in early 2009. Insufficient well data and risk analysis was included in the SCR for agency decision making. The Safe Case Revision processshould have been suspended until a complete set of plans was available.




1.99 The approved Safety Case Revision was based on a BOP in place for well control. Yet no BOPwas in place. And to make matters worse, the DA approved well plans that provided for well re-entry and tie-in with no BOP. The SCR identified the BOP as a critical Health Safety andEnvironment (HSE) piece of equipment, yet, the BOP was not even installed on H1 during re-entry.

1.100

The approved SCR did not examine the risk associated with non-standard equipment and the useof PCCCs to replace a cement plug as a barrier.

1.101 NOPSA should not have approved the November 2008 SCR absent HAZID assessments for theMontara well plans. Insufficient well data and risk analysis was included in the SCR for agencydecision making.

1.102 No HAZID was performed prior to PTTEP’s application to the DA to replace the cement plugwith a PCCC.

1.103 Replacement of a cement plug with a PCCC as a barrier was a “significant new risk” that shouldhave warranted a HAZID review, at a minimum, and review by NOPSA under the SCRcommitment.

1.104 NOPSA did not ensure PTTEP’s commitment to periodically examine hazards, risks, barriers andcontrols was met.

H1 Cost Savings

1.105 It is roughly estimated that more than $4MM (million) in cost savings on H1 were achieved bytaking shortcuts, not following approved permits, understaffing, avoiding quality control andquality assurance procedures, and taking unnecessary well control risks.

1.106 The Commission manifestly made the case that there is ample evidence to show that the otherMontara wells suffered similar neglect and shortcomings, compounding the cost savings by afactor of roughly five for a potential total savings of upwards of $20MM.

1.107 Authorization for Expenditures (AFEs) should include sufficient funds for safety, QualityAssurance (QA) and Quality Control (QC) procedures, adequate staffing, and engineeringevaluation and risk assessment when problems are identified. Government should ensure thesecomponents are included as non-discretionary items in the approved well plan.

1.108 In 2007 Advanced Well Technologies Pty Ltd (AWT) lodged serious complaints againstPTTEP’s cost cutting and risk taking on the Montara Project.

1.109 Companies need a confidential outlet or government provided avenue to report gross permitdeviations, safety violations or potentially hazardous situations.

Minimum Health, Safety & Environmental Regulatory Standards

1.110 The elimination of Australia’s prescriptive standards was a root cause of this incident. If Australia’s 2004 prescriptive standards for well control barriers were still in place, the exchangeof a 9-5/8” PCCC for a 45m (148’) long, shallow-set cement plug barrier would not have beenapproved, likely adverting this disaster.

1.111 As a reportedly more “modern” alternative to a prescriptive list of standards, in 2004 Australiadecided to allow industry substantially more flexibility in preparing applications and transitionedinto a regulatory regime of “self regulation.” Australian regulation places the onus on the operatorand contractors to minimize risk and prevent accidents, but provides flexibility on how best tomanage hazards and risk.




1.112 Australia’s regulations are unique, in that they weigh heavily “self regulation”.

1.113 In 2004, the regulatory pendulum swung too far away from prescription, into a regulatory regimeof almost exclusive self-regulation.

1.114 The term “good oilfield practice” was not adequately defined, leaving its application subject tounlimited government and industry interpretation. This opened the door for potentialmisapplication.

1.115 The regulatory term “good oilfield practice” needs to be more explicitly defined. The reviseddefinition should include health, safety and environmental objectives, and establish firm andunambiguous compliance yardsticks.

1.116 The lack of minimum prescriptive standards is even echoed by PTTEP’s Well ConstructionManager, as his own three decades of experience show that “good oilfield practice” is ambiguous,widely interpreted and is in large part a function of a person’s expertise and experience.

1.117 Where regulatory standards do not exist or are vague, the door is open to shortcuts and cost-cutting measures that can increase risk.

1.118 There was insufficient DA staff to review, approve, and oversee Timor Sea offshore drilling

operations.1.119 DA staff and management lacked the experience and qualifications needed to make complex

technical decisions required when reviewing waivers for well control barriers.

1.120 There was a culture of cozy relationships between the approving agency (DA) and industry.

1.121 There was a history of the DA “rubber-stamping” industry proposals with little or no independenttechnical analysis.

1.122 DA staff believed it was their job to issue permit decisions on the “fly” and avoid holding up rigoperations, regardless of the risk or complexity of the permit decision.

1.123 The DA had no formal written standard operating procedures for conducting technical reviews ormaking risk based decisions;

1.124 DA staff equated permit processing speed with successful job performance, rather than basingsuccessful job performance on the quality of the permit technical review and assessmentconducted at a reasonable, professional pace.

1.125 Government staff generally accepted most industry requests and proposals without adequatetechnical review.

1.126 History has shown that if government is too prescriptive, regulations do not keep pace withadvancing technological improvements or alternatives, frustrating industry innovation.Alternatively, history has also shown that the lack of unambiguous, minimum governmentstandards (“bottom-line” or “floor”) can result in shortcuts and cost-cutting practices that, in somecases, have catastrophic results. If government does not establish that basic “speed limit,”

offshore development has the potential to speed out of control. 1.127 A policy balance between prescriptive standards and technical innovation and flexibility must be

achieved. As governments develop regulations that aim to strike that balance, a stead-fast eyemust be kept on the ultimate goal of human health, safety and environmental protection.

1.128 In the oil and gas industry there is a set of prescriptive minimum standards that are sofundamental to meeting human health, safety, and environmental protection that they have beenused in regulation and practice for decades. This set of minimum prescriptive standards should becodified in laws and regulations.




1.129 Whether they are called minimum prescriptive standards or termed principle based regulations, abasic set of minimum standards is necessary to protect health, safety and the environment (HSE)and give government regulators a baseline for determining compliance.

1.130 The 2004 regulatory reform for Australian oil and gas exploration and development did notachieve a balance between prescriptive standards and latitude for innovation. It eliminated all

levels of prescription, defaulting to an undefined standard of “good oilfield practice.” This leftgovernment officials with an ambiguous standard to rely on to approve permits or measurecompliance.

1.131 A team of Australian and international industry experts could be gathered to identify a list of critical minimum prescriptive standards that should be codified in regulation to meet health,safety and environmental objectives.

1.132 A system can be established to update regulations on a routine basis to take into account technicalinnovation. A formal technical expert review process can be established to examine any proposedwaivers to the existing standards. Approval of proposed waivers should be based on anapplicant’s ability to demonstrate that it has developed a technology that meets or exceeds theminimum prescriptive standard, and that it is in Australia’s best interest to approve this technicalinnovation ahead of a regulatory amendment.

1.133 If the prescriptive, minimum standards of the Specific Requirements as to Offshore PetroleumExploration and Production were left in place, or used in a careful fashion to thoroughly examinethe proposed WOMP and subsequent drilling applications, then it is very likely that the H1incident could have been averted.

1.134 Minimum technical standards are critical. Flexibility can be afforded by allowing new technologyor alternatives that have been proven to provide “equal or greater protection” of human health,safety, and the environment.

Pre-Drill Risk and Impact Assessment

1.135 A root cause of this incident was complacency, because Australia’s last major offshore blowoutwas in 1984.

1.136 Blowouts are reasonably foreseeable consequences of offshore drilling and completionoperations. Pre-drill environmental assessments should include a risk and impact assessment of the worst-case blowout scenario. Human error and mechanical failure scenarios should beincluded.

Contractor Responsibility

1.137 The drilling contractor has a responsibility to provide technical advice to its client to ensure thatthe well is drilled safely and personnel are kept out of harms way.

1.138

If the Operator is unwilling to address or resolve health, safety or environmental concerns, thedrilling contractor should be required to report the problem to the appropriate agencies forimmediate resolution.

1.139 Legal protections should be in place for individual employees, as well as companies, to freelyreport safety concerns and prevent repercussions to those reporting safety violations.

1.140 Atlas Drilling should not have agreed to remove the PCCC without a BOP in place.

1.141 Atlas Drilling should not have agreed to leave H1 uncapped and move over to work on the GI andH4 well tie-ins, especially since gas bubbling was observed.




1.142 The cementing contractor (Halliburton) understood the problems with the failed float, wet shoe,and inadequate cement job, but did not raise the well safety concerns.

1.143 Regulatory requirements need to be established for contractors to ensure that they are required tostop unsafe acts, and immediately report and remedy unsafe operations. There should beincentives and protections in place for contractors that report, and there should be penalties for

those that don’t.1.144 Contractor’s legal requirements, rights and responsibilities to report safety and permit violations

warrant examination.

1.145 Minimum prescriptive standards, previous found in The Schedule of Specific Requirements as toOffshore Petroleum Exploration and Production at Section 513 should be re-established to ensurethat wells are never again left in an “unsafe condition” by the person in command of theplatform.

Inspections and Audits

1.146 Routine onsite inspections and audits are a critical component of a high quality regulatory

program. Crafting stringent regulations is only one step in the process. Routine inspections andaudits are needed to ensure that regulations and permit stipulations are followed, and to identifytechnical, safety, or environmental issues.

1.147 On August 21, 2009 the Montara H1 well blowout commenced. Over one year had passed sincethe Montara Wellhead Platform was installed in July 2008, and not even one onsite inspectionhad taken place by the DA, NOPSA or DEWHA.

1.148 The DA’s written submission painted a rosy picture of government oversight; whereas, DA staff testified they lacked sufficient technical personnel, funding resources, and technical backgroundto provide oversight and that they did not have the personnel or funding to conduct offshoreinspections to verify compliance.

1.149 A NOPSA inspection of the Montara Platform was warranted during its first year of activity.

Emergency Pre-Planning and Relief Wells

1.150 Locating a suitable, technically capable rig, with qualified crew, and executing a contractualarrangement for an extremely dangerous, hazardous mission should be part of advanced offshorewell planning.

1.151 Memorandums of Agreement and contracts for “mutual response aid” and emergency assistancewith other operators and contractors should be required as part of any offshore well plan.

1.152 Well control of a catastrophic well blowout is serious, highly technical, dangerous work. Relief well and well capping plans should be developed prior to drilling a well. During a catastrophic

emergency, there is insufficient time to be searching for well control experts, starting well controlplans from the beginning, or negotiating contracts for relief well rigs. This must be done inadvance to expedite emergency response.

1.153 Advanced agency approval of emergency response plans will enable quick decision making toensure that the window of opportunity to implement well control techniques does not expireduring protracted deliberations.




Lack of Engineering and Technical Resources

1.154 Not only was PTTEP under-resourced while drilling the Montara wells, it was also under-resourced during the response.

1.155

PTTEP assigned staff involved in the H1 blowout to drill the H1 relief well and conductemergency response activities. Good oilfield practice would have been to grant to staff that wereinvolved in events leading up to the blowout because they will understandably be very shakenand not in good condition for some time to do complicated, dangerous, and serious work.

1.156 Major changes of drilling personnel should be avoided during critical stages in a drilling programto ensure consistency. Changes in Atlas management oversight personnel during the same time of the H1 well completion (March 7) could have contributed to the lack of technical oversight andcommunication errors.

1.157 There was not enough engineering support out on the Montara Platform during drilling andcompletion operations.

Operator and Contractor - Training and Qualifications

1.158 PTTEP’s Well Construction Group exhibited technical errors in judgment that were inconsistentwith good oilfield practices.

1.159 Companies should have written QA/QC protocols and staff should be trained to implement them.

1.160 There was ample evidence unveiled during the Commission of Inquiry highlighting problemswith Third Party Support Contractors training and qualifications.

1.161 Offshore supervisors should be familiar with the permits; the permits should be on board; andthey should have at least a basic understanding of the regulatory requirements and a fullunderstanding of the permit limits. This enables rig staff make on the spot decisions withoutviolating permit conditions

1.162 Regulations should specify the training and qualifications needed to safely operate offshore.

Agency Decision Making and Oversight

1.163 When the Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production was revoked, there were no written guidelines put into place to instruct staff on howto make a determination about what constitutes good oilfield practice. This lead to technicallyunsupported decision making by the agency.

1.164 The DA approved the H1 well drilling, completion, and suspension applications without writtenstandard operating procedures or written minimum technical criteria defining “good oilfield

practice.” 1.165 Agencies need adequate technical and financial resources to review and approval drilling and

completion programs. There was inadequate agency resources assigned to the Montara Program.

1.166 Agencies should not issue “preliminary approvals” on offshore activities that will occur the nextday absent a complete application, because preliminary approval actually constitutes finalapproval because the physical change will have been made before a final decision is ever issued,completely negating any value in a formally issued final decision.




1.167 Permit approvals should only be granted by agency staff with requisite decision making authorityand the decision should be based on a technically sound analysis of the permit application.

1.168 Applications should be submitted for agency approval prior to completing the work, withadequate time for the agency to complete a technical review. After-the-fact permit approvalsshould not be approved by the agency.

1.169 There was no evidence provided of any substantive technical review by the DA in deciding toallow a PCCC instead of a cement plug. There was no evidence that the DA was familiar with thetechnical capabilities and risks of PCCCs.

1.170 The DA’s submittals to the Commission of Inquiry do not detail any engineering manuals,databases, lists, or regulatory guidance documents that staff relied on to make the determinationthat the Montara H1 applications met the “good oil field practices” standard.

1.171 A written, technical engineering assessment of the Montara H1 well applications and an agencydecision of fact and finding was nowhere to be found in the hundreds of pages of agencysubmittals and exhibits to the Commission of Inquiry. The DA submittals asserted that “good oilfield practice” was met, but no technical documents or other evidence to support that conclusionwas provided.

1.172 The first Phase of the H1 well was drilled without the required Environment Plan approved by theDA.

1.173 The H1 oil spill plan was not approved by DEWHA until March 6, 2009, after the first phase of the well was drilled.

1.174 H1’s phase 2 re-entry plan was approved in four business days, with no apparent technical orsafety peer review by RET or NOPSA.

1.175 Agency inspection and oversight was inadequate on the Montara Platform and for the MontaraDrilling and Completion Operations. Agencies should be responsible for compliance monitoring.

1.176 The DA should not have approved the H1 suspension permit because it did not contain a “two-barrier” control system. A waiver allowing cement barriers to be removed from the H1 wellsuspension plan was not technically justified, and was unsafe.

1.177 Financial responsibility requirements for offshore operators should be clearly articulated in theregulation such that staff can verify compliance.

Agency Coordination

1.178 The DA’s claim that multi-agency consultation was completed appears to be unsupported, basedon the records and submissions of the other agencies that provided information to theCommission of Inquiry.

1.179 Agencies should work cooperatively and professionally to ensure seamless oversight over

offshore operations. There should be clarity on the point at which one agencies responsibilitiesend and the other agencies responsibilities begin.

1.180 The DA did not consult with RET or NOPSA before making major changes to the wellcompletion and suspension plan, in conflict with Australia’s Guidelines for Offshore WellOperations that direct the DA to consult with NOPSA and RET.




Agency Training and Qualifications

1.181 A regulatory system that relies on good oilfield practice, rather than a prescriptive list of standards required trained, qualified, and experienced staff capable of reviewing and approvingalternative procedures.

1.182 DA did not have a sufficient number of trained and qualified staff, nor management to effectivelyand safely oversee offshore oil and gas well operations.

1.183 Agencies should have written QA/QC protocols and staff should be trained to implement them.

1.184 All governments face challenges in hiring and retaining qualified personnel in regulatorypositions. In order to hire and retain qualified personnel government agencies need to offer salaryand benefit packages commensurate with those offered by oil and gas companies and theircontractors.

2. Introduction

This analysis updates a report submitted to the Montara Wellhead Platform Uncontrolled HydrocarbonRelease 1 Commission of Inquiry on March 3, 2010. Findings and recommendations made in the March 3,2010 report were based on the exhibits and testimony in the public domain at that time. Since the initialreport, extensive new information, documents, testimony, evidence, and other material has becomeavailable for public review through the Commission of Inquiry process. Updated findings andrecommendations in this report reflect that extensive new data. This report is based on data publiclyavailable at the Commission website. The Commission secured additional data during the Inquiry processand held some information confidential. This report does not include any analysis of that confidential databecause it was not available to the author.

While the Commission of Inquiry examination scope is broader than the technical and regulatory issues

related to drilling and well control (e.g. oil spill response, human health impacts, environmental impacts),this report is solely focused on the technical and regulatory issues related to drilling and well control.

Findings and recommendations in this report are based on 23 years of experience as a Petroleum andEnvironmental Engineer, and are highlighted in blue text boxes.

3. Incident Summary

The information provided by both PTTEP Australasia (Ashmore Cartier) Pty Ltd. (PTTEP) and AtlasDrilling (S) Pte Ltd. (Atlas Drilling) confirms that the H1 “Uncontrolled Release” occurred one day afterthe West Atlas drilling rig moved over the well to tie it back into the Montara Wellhead Platform. Theplan was to tie H1 into the platform wellhead control system and finish the second phase of drilling(production interval).

On August 20, 2009, the West Atlas re-entered H1 to tie it back into the wellhead control system. Delaysand problems tying in the well resulted in the West Atlas moving from H1 to gas injection well GI, andlater to production well H4, leaving H1 uncapped, while the drilling staff’s attention was focused on tyingin wells GI and H4.

1 The term “Uncontrolled Release” is used by the Commission of Inquiry. In this report, synonymous terms used will include “well blowout” or“blowout.”




The blowout commenced on August 21, 2009. When the uncapped H1 well blew out, the West Atlasdrilling rig was working over H4, holding a heavy string of 20” casing. The 20” casing had to be set downbefore the West Atlas could be moved back to H1 to commence any well control operations. This causedfurther delay in providing emergency response to H1.

Control of the H1 Montara Well blowout required a separate relief well rig. It took 74 days (2.5 months)to initially kill the well, and 135 days (4.4 months) to completely secure the well to abandonment status.The relief well rig intersected the Montara H1 well on November 3, 2009. Cement was pumped onNovember 3, 2009 to control the well, but the well was not finally abandoned until January 13, 2010,when two barriers were placed in the well. 2

PTTEP estimates H1 spilled approximately 400 barrels of oil per day (bopd), amounting to approximately29,600 barrels of oil spilled over the 74 day blowout. 3

The history leading up to the blowout is summarized as follows:

Between January and April 2009 the West Atlas batch drilled the Montara production wells (H1, H2, H3,and H4) 4 and gas injection well (GI) down to the 244mm (9-5/8”) intermediate casing, and thensuspended each well on the Montara Wellhead Platform. 5

On January 18, 2009 well H1 was spudded (started) as a horizontal production well from the WHPfacility jacket. 6

H1’s well suspension plan originally required a cemented casing shoe at the base of the well (as the 1 st barrier) and a 45m (148’) long, shallow-set cement plug set from 115m to 160m (as the 2 nd barrier), aswell as MLS corrosion caps. 7 Installation of two cement plug barriers and MLS corrosion caps isconsistent with good oil field practice.

On March 6, 2009 well H1’s 9-5/8” intermediate casing was set. 8 PTTEP emailed the DA requesting last

minute approval (at 2:37pm on a Friday afternoon) for a major change in well control barrier plans to beimplemented the next day. PTTEP did not submit a formal application for this change on March 6, 2009;the formal application did not come until March 12, 2009, six days later, after the well had already beensuspended on March 7, 2009.

A DA staff member without requisite authority granted PTTEP “preliminary” approval to not install the45m (148’) long, shallow-set cement plug in exchange for upgrading the standard temporaryabandonment caps (“corrosion caps”) to pressure containing corrosion caps (PCCCs) in the 9-5/8” and13-3/8” mudline suspension systems (MLS). 9

On March 7, 2009 well H1 was suspended and a 9-5/8” intermediate casing Pressure Control CorrosionCap (PCCC) 10 was installed based on a “preliminary approval”. 11

2 http://www.upstreamonline.com/live/article203344.ece3 Commission of Inquiry Transcript, April 12, 2010, p. 19214 Atlas Drilling, Submission No. 1501.0001.00025 PTTEP, Submission No. 1000.0001.00346 PTTEP Montara Incident Report 10-2-09 Issued to NOPSA7 Commission of Inquiry Document, SEA.010.001.00108 Atlas Drilling, Submission No. 1501.0001.00029 Commission of Inquiry Document, SEA.010.001.001010 Also commonly referred to as a temporary abandonment cap on a mudline suspension system or “TA”.11 Atlas Drilling, Submission No. 1501.0001.0002




Five days later, on March 12, 2009, PTTEP formally issued a change control order to the H1 wellsuspension plan. 12 This change order was issued after-the-fact – the well had already been suspendedand the decision had already been made not to set a cement plug.

On March 13, 2009, the DA approved the March 12, 2009 application for the PCCC placement,issuing a formal final approval after-the-fact. PTTEP set the 9-5/8” PCCC, but did not follow throughand place the 13-3/8” PCCC.

On April 21, 2009, the West Atlas left the Montara Wellhead Platform to conduct exploration drillingat other locations .13

Four months later, on August 19, 2009, the West Atlas returned to the Montara Wellhead Platform totie in H1, H2, H3, H4, and GI wells .14

On August 20, 2009 the West Atlas skidded over H1 and commenced well tie-in work .15 PTTEPfound H1 without a 13-3/8” PCCC. The 13-3/8” surface casing threads were discovered to becorroded and scaled. Rig staff removed the 9-5/8” PCCC with the intent of cleaning the 13-3/8”surface threads.

Leaving H1 uncapped, the drilling staff’s attention for the next 12 hours turned to tying in wells GIand H4. On August 20, 2009 and into August 21, 2009 the West Atlas skidded over GI, and then towell H4 to commence well tie-in work .16

On August 21, 2009 the H1 well uncontrolled release (otherwise commonly referred to as a“blowout”) commenced .17 Atlas Drilling reports an estimated kick of 40 barrels of fluid and anunknown quality of gas were released, activating gas alarms and emergency response. 18 When thealarms sounded, the West Atlas was over well H4, not H1. This required the West Atlas to lay downthe 20” casing that was just cut off from H4 before the rig could be moved back to well H1, furtherdelaying response to the uncontrolled release. 19

Plans were made to run PTTEP’s cementing contractor’s down-hole packer into well H1 to secure it,once the West Atlas could be activated. The down-hole packer was never set, because the MontaraPlatform was evacuated for human safety.

The H1 well blowout occurred because hydrocarbons flowed through cement channels in the 9-5/8”intermediate casing shoe track. 20 The casing shoe track, if properly cemented, plugs off hydrocarbon entryinto the bottom of the well. If improperly cemented, the casing shoe track can provide a conduit forhydrocarbons to enter the well.

The H1 well was drilled to a total depth of 3,796m (12,454’). The 9-5/8” intermediate casing string wasdrilled at a high angle through 1,187m (3,894’) of a pressurized hydrocarbon zone. The failed 9-5/8”

12 Atlas Drilling, Submission No. 1501.0001.000213 PTTEP, Submission No. 1000.0001.003414 Atlas Drilling, Submission No. 1501.0001.000415 Atlas Drilling, Submission No. 1501.0001.000416 Atlas Drilling, Submission No. 1501.0001.000517 Atlas Drilling, Submission No. 1501.0001.000518 Atlas Drilling, Submission No. 1501.0001.000519 Atlas Drilling, Submission No. 1501.0001.000620 PTTEP, Submission No. 1000.0001.0041-42




intermediate casing shoe track was 3m (10’) above the oil-water contact, 21 providing a pathway forhydrocarbons to enter the well though the cement shoe. The 9-5/8” casing shoe track sitting at the base of this casing string was subject to the pressure forces encountered at the total well depth of 3,796m(12,454’).

Major drilling mud losses were encountered through the Lower Johnson and Upper Puffin formationsfrom 1,707m (5,600’). Lost circulation, stuck pipe and hole stability problems resulted in abandonmentof H1’s original well target and required the well to be sidetracked to a bottomhole location (renamed H1-ST).22 H1 intermediate (9-5/8”) casing was set in a sandstone reservoir at a 90.3 degree angle. 23

A “back-side” (annular) blowout via the 9-5/8”/13-3/8” annulus was ruled out by PTTEP as a cause,based on information obtained during the relief well operations. 24 PTTEP reports the H1 relief well wasdesigned to intersect the 9-5/8” casing; when the relief well intersected, hydrocarbons were controlled bypumping mud into the 9-5/8” casing. A relief well eventually controlled well H1. Very little technicaldata was provided on relief well operations. It is possible that a poor annular cement job contributed tothis accident.

The leading blowout theory is that the PCCC installed on the 9-5/8” intermediate casing may have hadheld a slight backpressure on the well sufficient to contain the flow. When the PCCC was removed, thepressure flow regime changed, allowing higher bottom hole pressure fluids behind the 9-5/8” intermediate casing to leak though a poor cement job at the casing shoe, into the 9-5/8” intermediate casing, past thebrine in the casing string, and up to the surface of the platform floor. The weight of the brine left in thehole when the well was temporarily suspended was inadequate to counteract the highest potentialreservoir pressure expected in the well.

The facts listed above were disclosed during the Commission of Inquiry process, which occurred 8-9months after the blowout. Most of these basic facts were known to both PTTEP and the governmentduring the fall of 2009, but were not disclosed to the public. While PTTEP issued 97 press releases, therewas no significant information ever provided to the public on the cause of the blowout, 25 nor did thegovernment communicate this information until the Inquiry process made it available in 2010.

4. Findings and Recommendations

The Commission of Inquiry is commended for developing a thorough and transparent process for the H1Montara Well blowout investigation. The investigative process provided an opportunity for bothcorporate and public interest groups to provide input and advice. The Commission established protocolsand processes and effectively communicated its plans via routine updates to its website. Submissions,transcripts and exhibits were efficiently disseminated to the public through a website that was kept currentthroughout the investigative process. The Commission of Inquiry’s commitment to unearthing the failuresthat led to the blowout allow for both government agencies and industry to identify improvements tooilfield practices and regulation. If these identified improvements are undertaken to their full extent, it

will better position industry for safe operations.

21 PTTEP, Submission No. 1000.0001.0041-4222 PTTEP Montara Incident Report 10-2-09 Issued to NOPSA23 PTTEP Montara Incident Report 10-2-09 Issued to NOPSA24 PTTEP, Submission No. 1000.0001.004125 Commission of Inquiry Transcript, April 12, 2010, p. 1871




4.1 Montara G1, H2, and H4 Well Integrity – Immediate Well Control Intervention Needed

The March 3, 2010 WWF report submitted to the Commission raised serious concerns about potentialwell control problems that may exist on other Montara wells. The WWF report stated:

“ Of urgent and primary concern to the Commission of Inquiry should be the existing safety statusof all the other wells on the Montara Wellhead Platform. While H1 is now, reportedly, secured with a two-barrier system, it is not clear if the other wells are safely secured. Batch drilling

programs, by nature, are subject to repetitive flaws. Flaws encountered on H1 could have been repeated in the other wells, and this warrants inquiry . The Commission of Inquiry should alsoexamine whether similar well safety concerns could exist on other offshore platforms [emphasisadded].”

Testimony confirmed repetitive flaws in other Montara wells (GI and H2). The Commissioner questionedPTTEP Well Construction Manager (Mr. Duncan) about the condition of the other Montara gas injectionand oil wells:

“Q. Is it the case that every PCC that was installed on any of the wells was not tested? A. I don't believe they were, no.Q. So that's an issue?

A. It is.Q. You have non-verified barriers?

A. Correct.Q. Secondary barriers; is that right?

A. That's correct.Q. And on GI, we have a serious question mark raised over the integrity of the primary

barrier? A. We have an issue with it, yes.Q. So it seems as though, in terms of compliance with PTT's own well construction standards, the

situation is that not a single well is compliant ? A. Given that we didn't test those corrosion caps, no.Q. Do you mean you agree with me?

A. Yes [emphasis added].” 26

PTTEP Well Construction Manager (Mr. Duncan) testified that he did not know about the status of anyremedial actions that might have been taken to address the well integrity problems on the other Montarawells; nor could he confirm if the DA or NOPSA were notified of the problems. 27

Mr. Jacobs (PTTEP CEO Australasia) testified that there were systemic problems with the WellConstruction Group’s implementation of the Montara Well Program:

“Q. Sir, I want to suggest that, despite what you've said, we really are pretty much located in the terrain of endemic or systemic sloppiness ; will you agree with me? A. There's been failures in the systems and by the personnel, yes.Q. Which have been expressed in relation to just about every barrier that was installed in all of

the five wells out at Montara? A. The majority of the barriers, yes.

26 Commission of Inquiry Transcript, April 7, 2010, p. 150827 Commission of Inquiry Transcript, April 7, 2010, p. 1539




Q. Well, every barrier on H1 well; that's right, isn't it? A. That's correct, yes.Q. And every secondary barrier on all of the other wells?

A. That's correct, yes.Q. And the primary barrier on GI?

A. Yes, there's some concern, yes.Q. Yes. So we are talking, are we not, about a substantial, systemic level of inattention to

achievement and maintenance of well control? A. Yes [emphasis added].” 28

Mr. Jacobs (PTTEP CEO Australasia) testified that he was disappointed to find out that his staff did notfollow PTTEP or generally accepted engineering standards:

“Q. You say, do you, that you weren't shocked to learn of that evidence; you were just disappointed that, basically, PTT had not managed to suspend a single well in conformity withits own standards ?

A. I was surprised that that was the case, and I was disappointed in the personnel, that they hadn't followed the company guidelines or control standards .Q. Do you agree, sir, that that fact speaks of fundamental and widespread inattention to

ordinary, sensible oilfield practice ? A. I don't know whether you would call it widespread. It obviously does within the well construction group.Q. I'm not talking about how widespread in terms of personnel; I'm talking about how widespread in terms of well management. We have five wells out at Montara; that's right, isn't it?

A. Yes.Q. Not a single one of them has been suspended in a manner which complies with PTT's ownwell construction standards?

A. That's correct.Q. Do you agree that that speaks of a fundamental and endemic inattention to ordinary,

sensible oilfield practice? A. Fundamental, yes.Q. And widespread or systemic?

A. Within the group, yes.Q. I mean, it is not idiosyncratic, is it? We're not talking about a one-off lapse or error of

judgment, are we? A. It appears not, no. [emphasis added].” 29

Since the H1 blowout personnel have returned to the Montara Platform to cap H1, yet there is no apparentplan to safely control the other Montara wells, in light of the unknown risks. 30

No action has been taken to remedy these well integrity issues at this time. 31

GI, H2 and H4 well integrity issues warrant immediate attention.

March 26, 2009 (19 days after H1 was suspended) PTTEP records show that the GI well had a gas leak. 32

28 Commission of Inquiry Transcript, April 7, 2010, p. 169229 Commission of Inquiry Transcript, April 7, 2010, p. 1621-162230 Commission of Inquiry Transcript, April 12, 2010, p. 187731 Commission of Inquiry Transcript, March 26, 2010, p. 100432 Commission of Inquiry Document, EXH.0002.0001.0001




“G-I has commutation between the 13 3/8”casing and the 9 5/8” casing annuals its bubbling all the time now and slowly getting worst , we put a plastic garbage bag over it and collected some gas and it has some heavies in the sample. G-I is temporary abandon with a 9 5/8” MLS pressure plug made up and then we install a second MLS 13 3/8” pressure plug so if you are the one toreturn, you will surly find pressure under the 13 3/8” Plug [spelling errors in original text;emphasis added].” 33

Similar to H1, GI was suspended without a shallow set cement plug inside the 9-5/8” casing. 34

“Of the 5 wells drilled and suspended during the initial drilling phase, the ‘As Built’ suspensiondiagrams show wells H1 and GI had 9-5/8” and 13-3/8” PCCC’s fitted with no shallow set 9-

5/8” cement plug . The remaining Wells H2, H3 and H4 had 13 3/8” PCCC’s installed inconjunction with a shallow set 9-5/8” cement plug (160m – 115m)[emphasis added].” 35

Realizing that H1 well control problems could be duplicated in GI because both wells were completedincorrectly, PTTEP hired a well engineer (Mr. McGregor) to assess GI’s condition. McGregor’s October19, 2009 report concludes:

“GI is currently suspended with a pressure containing 9-5/8” corrosion cap ( untested ) installed in the 9-5/8” ML hanger plus a pressure containing 13-3/8” corrosion cap ( untested ) installed inthe 13-3/8” ML hanger plus a trash cap installed [emphasis added].” 36

“However, the gas bubbles which were being monitored and ultimately addressed with theinstallation of a 13-3/8” pressure containing cap add more complexity. Since the source or

composition of the gas bubbles is unknown and taking a worst case view, the casing cement job has been either compromised internally (unlikely given the good pressure test) or the annulusis not sealing (channeling or a micro annulus ) [emphasis added].” 37

“With regards to the status of either of the corrosion caps installed, as far as I can see neither of

them were positively pressure tested and so cannot be considered a barrier under themanagement system Section 5 [emphasis added].” 38

“Well GI requires remedial work due to a poor 9 5/8” casing cement job so it is not adequatelybarriered off [emphasis added].” 39

Yet, even months after its own independent engineer investigated problems with GI, PTTEP Managementdenied any GI well cement problems when questioned by the Commissioner:

“THE COMMISSIONER: Mr. Howe, from looking at this email string from Mr. McGregor, doesthat mean that, in his opinion, there should be major questions asked about the integrity of theGI well?

MR HOWE: He certainly seems, in the summary, to be expressing a view about the integrity of the 9-5/8" cement job in the GI well.

33 Commission of Inquiry Document, EXH.0002.0001.000134 Commission of Inquiry Document, EXH.0002.0001.000135 Commission of Inquiry Document, SEA.010.001.001536 Commission of Inquiry Document, PTT.9002.0106.023937 Commission of Inquiry Document, PTT.9002.0106.023938 Commission of Inquiry Document, PTT.9002.0106.023939 Commission of Inquiry Document, SEA.003.015.2953




THE COMMISSIONER: So that would raise questions not just about the H1 well but about all of the potential wells on the Montara platform? MR HOWE: It may, although I assume that, in light of this - perhaps I'm wrong - PTT took stepsto either draw to the regulator's attention any perceived deficiencies, or took remedial action,rather than simply leaving things in the state of affairs as described by Mr. McGregor.Q. Do you know anything about the question raised by the Commissioner?

A. There were no issues during the cementing of the GI well .Q. Do you mean no issues raised during the course of that cementing?

A. There were no issues raised during the course of the cementing, and the cement job was fine; the casing was tested.Q. Well, you agree, though, that Mr. McGregor, as at 19 October, is sending to your supervisor,

Mr. Duncan, his own assessment that there is an issue about the quality of the 9-5/8" cementing job in the GI well? A. Yes, as it mentions in there, there's gas bubbles – or were bubbles observed in the annulus. Now, the source of those bubbles could be - and I believe it's not uncommon for mud to be goingoff, actually deteriorating, and as it deteriorates, it generates bubbles [emphasis added].” 40

The GI well gas leak was not identified as a serious well integrity problem, which it should havebeen. Immediate intervention was warranted when the gas bubbling problem was found.

Mr. Ross’s (Atlas Drilling Consultant) October 29, 2009 report concludes that there were a number of well integrity concerns with H1, GI, H2 and H4. While drilling the 17-1/2” hole and below the 13-3/8” shoe there was:

“[drilling mud] losses in GI with communication to H4;[and] losses in H2 with communicationto GI and H4. In H2 no satisfactory 13-3/8” shoe test could be obtained and severe losses wereencountered immediately below ( thus the chances of a good 13-3/8” cement job on this well are

slim ) [emphasis added].” 41

“ Gas has been observed up the 13-3/8” x 9-5/8” annulus on both GI (and possibly H1)indicative of cement channeling and leak path to surface which is quite concerning…measures should have been taken to isolate the leak [emphasis added].” 42

“ The 9-5/8” casing string in GI is set at 35 deg while the other 4 wells have 9 5/8” set horizontally. It would therefore be expected that the GI job would be better than on the horizontal producers. However, it is evident that there is minor gas communication to surfaceup the 13-3/8” x 9-5/8” annulus (reported on numerous occasions) [emphasis added].” 43

“ In H4 the 13-3/8” cement job displacement was under displaced most likely due to a rig pump problem or pit running dry. Cement was tagged 481m above the shoe which meant only 109m of cement was placed into the annulus [emphasis added].” 44

Mr. Duncan (PTTEP Well Construction Manager) testified that: the PCCCs were not tested on H2, H3,H4, and GI; the casing shoe may also be defective on GI because of the gas bubbling observed; and one

40 Commission of Inquiry Transcript, March 26, 2010, p. 100441 Commission of Inquiry Document, SEA.003.015.295142 Commission of Inquiry Document, SEA.003.015.295243 Commission of Inquiry Document, SEA.003.015.295244 Commission of Inquiry Document, SEA.003.015.2952




of the wells didn’t bump the plug and the casing wasn’t tested, and the testing still has not been done (hebelieves the problem was on H2, but wasn’t sure). 45

Good oilfield practice includes verifying actual cement placement depths in the well and cementbond integrity prior to removing the BOP and skidding the rig off the well. This was not done in

any of the Montara wells.

4.2 Live Wells Require Safe Handling

All wells drilled into hydrocarbon zones must be treated as live wells, with the potential to flowhydrocarbons to the surface, unless technical evidence is collected to prove otherwise.

The complexity of the H1 well and the mere fact that it penetrated a pressurized hydrocarbonzone containing oil and gas should have warranted PTTEP and Atlas Drilling to treat this well asa “live” well, with the potential for hydrocarbon flow. The need for pressure barriers to beinstalled to “safe-out” the well while it was suspended, and the need to set a BOP as part of there-entry process, should have been standard well control procedure.

Halliburton cementing staff on the rig (Mr. Doeg) was not aware that that the 9-5/8” casing was set in thehydrocarbon zone. 46 The fact that the wellbore penetrated a pressurized hydrocarbon interval is criticalinformation that should have been communicated to all parties involved with the H1 well, because of theserious implications associated with a failed cement job in the hydrocarbon zone. This information alsohas substantial bearing on any future decisions about the number of barriers to set in the well and theremoval timing of the BOP.

PTTEP provided conflicting information on its two-barrier policy. Mr. Duncan (PTTEP WellConstruction Manager) argued that it is PTTEP policy to always use a two barrier system, but then listedset of situations where a two barrier policy (in his opinion) can be relaxed for short periods of time:

“There are times when multiple barriers are not in place . An example of this would be that shortly after cementing casing, there is a time when, on jackup rigs or land well operations, it iscommon to nipple down BOP’s, cut the casing and install an additional wellhead section and then nipple up BOPs again. During the time that the BOP is nippled down, not all the normal

barriers are in place. When we had our problem on Montara H1 ST1, we were in such asituation. I am confident that this exposure also occurs every day in USA [emphasis added].” 47

A two barrier policy is not effective, unless continuously implemented. In the USA, a two barriersystem is required to be in place at all times. 48 Other Australian approving authorities also advised theCommission it is their practice to require two barriers. Continuous well control is key to controllingblowouts.

In June 2009 the DA approved a H1 well completion plan (DP 1B) 49 that allowed the 9-5/8” casing to beexposed to atmosphere for an extended period of time with only one barrier in place.

45 Commission of Inquiry Transcript, March 30, 2010, p. 134246 Commission of Inquiry Transcript, March 19, 2010, p. 45247 Commission of Inquiry Document, PTT.9003.0074.012548 USA Minerals Management Service Regulations at Title 30, Code of Federal Regulations, Part 25049 Document TM-CR-MON-150-00003, July 6, 200, Montara Phase lB Dri lling & Completion Program (DP 1B) covers removal of the PCCC.




The BOP should not be removed until at least two independent, pressure tested barriers areinstalled in the well. Both barriers should remain in the well until well control is establishedeither by replacing the BOP or connecting to a wellhead control system. It is not good oilfieldpractice to leave only one barrier in place, even for a temporary period of time.

PTTEP states that its Montara Batch Drilling Program does not call for setting BOPs until the existingcasing and conductor strings are tied back and the production wellhead is installed. 50 Yet, the MontaraBOP installation timing assumed there would be at least two pressure tested barriers set in the well andthat neither barrier would be removed until a BOP was set. The decision to change the type of barriersinstalled in H1 should have been examined holistically, with attention given to how it would affect BOPinstallation timing.

Instead, PTTEP never set the 13-3/8” PCCC barrier and removed the 9-5/8” PCCC, leaving only a single,flawed cement shoe in the base of H1. No BOP was set before barriers were removed, contravening goodoilfield practice.

The 7-Day Operational Forecast for August 21, 2009 showed the 9-5/8” PCCC wasn’t scheduled for

removal until August 24, 2009 at 4pm, but it was actually removed mid-day on August 21, 2009.51

Thismeans the 9-5/8” PCCC was removed 4.5 days in advance. The BOP wasn’t scheduled to be installeduntil August 26, 2009. 52

Installation of only a single well barrier is not good oilfield practice for wells where theintermediate casing shoe is set 3m (10’) above the water-oil contact and the casing string is setthrough 1,187m (3,894’) of hydrocarbon zone.

PTTEP and Atlas Drilling penetrated the H1 hydrocarbon interval in early 2009. Fundamental petroleumengineering principles and practices include the need to maintain well control throughout the welldrilling, completion, suspension, and production processes. Once the hydrocarbon zone is penetrated, thealert status for that well is elevated. The well becomes a “live” well, and must be treated as such.Temporary barriers can fail; thus more than one barrier must be installed as a back-up. A redundantsystem of well control barriers is industry practice.

DA staff acknowledged failings in barrier decisions. Mr. Marozzi testified:

“A. I probably did not give adequate compliance monitoring attention in terms of probably not realising, or failing to realise, at the time of this cement job that the rig in fact was going to goaway 53…. I think I neglected that part about validating that primary barrier, given that the rigwas going to leave [emphasis added].” 54

“Q.Yet, a few days after receiving information which you have said created an awareness that there were doubts about the integrity or the effectiveness of the primary barrier, you nevertheless recommended approval of the suspension of the well, didn't you ? A. That's right [emphasis added].” 55

50 PTTEP, Submission No. 1000.0001.004351 Commission of Inquiry Document, PTT.9001.0007.036852 Commission of Inquiry Transcript, March 26, 2010, p. 109953 Commission of Inquiry Transcripts, April 14, 2010, p. 210254 Commission of Inquiry Transcripts, April 14, 2010, p. 211155 Commission of Inquiry Transcripts, April 14, 2010, p. 2103




“Q. Do you agree , then, that with hindsight, it was not good regulatory practice to have recommended approval of the 1B drilling program that was going to have the consequence that the H1 well was open to atmosphere with only one barrier in place for approximately 8 to 10 hours? A. That’s a fair comment [emphasis added].” 56

“Q. I suggest, Mr. Marozzi, that relying on only the cemented casing shoe as a barrier operating against a blowout for any period of time is not good practice, but that's particularly the case when there have been problems identified with the cementing of that casing shoe; do you agree with that? A. I agree [emphasis added]. ” 57

Western Australian Department of Mines and Petroleum wrote to the Commission that it wo uld notpermit an un-depleted live well to be open with only one primary barrier and a hydrostatic head of wellbore fluid in place and would not approve an intervention or re-entry based on such a proposal. 58

Victorian Department of Primary Industries advised the Commission that it is not good practice to rely ona cemented casing shoe as the only barrier operating against a blowout, even where the integrity of thecemented casing shoe has been confirmed by appropriate testing. 59

Wells drilled into hydrocarbon reservoirs must be treated as live wells with the potential to flowhydrocarbons to the surface, unless engineering studies demonstrate the well is not capable of unassisted flow to the surface.

4.3 Wellbore Gas Bubbling Requires Immediate Attention

Gas bubbling in the completion fluid was observed in both the H1 and GI wells by the rig crew. Stepswere not taken to properly address the hazard. Gas bubbling in the completion fluid is an indication of gas

influx into the wellbore and should have triggered an engineering assessment and immediate well controlintervention steps.

Three major danger warning signs were ignored: (1) a failed float valve, (2) a poor cement job,and (3) gas bubbles that were detected when the PCCC was removed. The seriousness of gasbubbling is compounded when it is correlated with a failed float valve and poor cement job,because this indicates the likelihood of gas percolating through the failed cement job.

In the case of H1, the rig should have remained over H1 and a downhole packer should have beenimmediately set for well control, followed by setting a BOP. Moving a rig off a well with known gasinflux and subsequently leaving the well open to atmosphere for more than 15 hours is not good oilfieldpractice.

Atlas Drilling’s August 21, 2009 H1 Investigation Report stated PTTEP Drilling Supervisor (Mr.Robinson) was at the MLS deck level when the 20” trash cap was removed from H1:

56 Commission of Inquiry Transcripts, April 14, 2010, p. 212757 Commission of Inquiry Transcripts, April 14, 2010, p. 213058 Commission of Inquiry Document, DMP.9001.0001.000159 Commission of Inquiry Document, DMP.0002.0001.0001




“Mr. Robinson noted ‘… bubbles discharging from the 13-3/8” x 9-5/8’’ annulus although nohydrocarbon smell or gas detector reading [emphasis added].” 60

Mr. Robinson’s statement read:

“Removed H1 ST-1 trash cap and recovered to top WHP deck. Inspected H1 ST-1 stump and observed powdery cement pieces on top of corrosion cap and between 13-3/8” x 9 5/8’’ annuluswhich easily broke down to dust when handled (largest size would have been 4’’ x 2’’ in size). Mytheory on this is the cement had fallen down when BOP and diverter system was removed.

Proceeded to clean out around 9 5/8” corrosion cap and annulus. At this point I observed bubbles discharging from the 13-3/8” x 9 5/8’’ annulus . There was no hydrocarbon smell omitting fromannulus and subsequent gas detector readings confirmed no hydrocarbons present. Gas detector readings were performed periodically while working at the MLS level and all resulted in zeroreadings. There was no oil at surface and no flow evident from the well. Paul O’Shea had alsoinspected the annulus and was satisfied all was ok [emphasis added.”

Low or non-existent gas readings provided a false sense of safety. Bubbling seen in the wellbore was aclear warning sign, indicating possible communication with the formation, and the likelihood of a poorcement seal as a causal factor. Regardless of the magnitude of the initial gas readings, the fact that gaswas bubbling in the completion fluid should have immediately triggered hazard assessment andintervention, especially because H1 did not have a BOP set, nor was the well hooked up to amud/completion fluid circulation system to control well pressure. Small gas releases can rapidly catapultinto major gas releases. Removal of the 9-5/8” PCCC likely created the pressure differential in thewellbore needed to trigger the escalation of gas flow from the reservoir, through the failed cement shoe tothe surface.

A few hours later, when the gas was again monitored, the reading was at 75% of the Lower ExplosiveLimit (LEL).

“Drilling Supervisor Brian Robinson made the following observations at this time: ‘The way the fluid was discharging was a distinct vertical column and it was falling back into the centre of thecolumn which gave me the impression that it was unloading from the 13 3/8 x 9 5/8’’ annulus.Within 5 seconds the fluid had reached the underside of the rig floor and the gas alarmsactivated. The fluid itself looked like oil and no sign of the inhibited seawater pumped into thewell prior to suspension.’ A gas monitor was used to take reading at the WHP helideck levelimmediately after this discharge and the LEL reading was at 75% (note that the atmosphere is

considered hazardous if LEL >10% - OSHA) [emphasis added].” 61

Gas bubbling in and of itself should have led to immediate well intervention, because as evidenced in thiscase gas levels can quickly escalate when you are dealing with a live well.

Mr. Treasure (PTTEP Drilling Rig Supervisor) argued that it is “good” practice to determine well stabilityby looking into a wellbore to see if it is “bubbling.” 62 Yet, it is not good oilfield practice to remove wellbarriers and visually assess wellbore stability by looking for gas bubbling, without a BOP in place.

60 Commission of Inquiry Document, SEA.010.001.001861 Commission of Inquiry Document, SEA.010.001.002362 Commission of Inquiry Transcript, March 19, 2010, p. 399




PTTEP Well Construction Manager (Mr. Duncan) was on the rig August 20, 2010 when the H1 9-5/8”PCCC was removed and rig staff reported observing bubbling. 63 Yet, as the Senior PTTEP manager, Mr.Duncan took no steps to advise the rig staff to secure H1.

Wellbore gas bubbling is direct evidence of gas influx, which is a very serious well safety issuethat requires immediate hazard assessment and intervention.

The August 21, 2009 Atlas Drilling Incident Investigation Report concluded:

“There have been at least two documented comments related to the integrity of the annuluscement jobs.

Communication in H1 13-3/8” x 9-5/8” annulus : Observation of Bubbles seen in 13-3/8” x 9-5/8” annulus by Drilling Supervisor following

the removal of Trash Cap (Thurs 20 Aug 2009) – Statement Brian Robinson) Evidence of gas bubbling in Well GI while being suspended during Phase One “The 244mm

(9-5/8”) casing was run and set at 2880m MD, where the plugs did not bump however the

floats held. The casing was backed out at the MLS and a pressure containing corrosion capwas installed. Sometime later, gas was observed at surface to be bubbling up the 244mm (9-5/8”) x 340mm (13-3/8”) annulus – it was suspected that this gas was migrating from a smallsand within the Woolaston formation. Future wells had 244mm (9-5/8”) casing centralisersrun +/-100m across this sand, and the lead cement volume increased, ensuring this sand wasisolated.”

Communication between Wells H4 and GI , Phase 1 Drilling (Jan – Apr 2009):Several statements made by drilling personnel regarding ‘communication’ between the wellsduring drilling, including one specific recount of communication between Wells H4 and GI during drilling operations [emphasis added].” 64

Atlas Drilling Manager (Mr. Millar) stated:

“ During the drilling operations for wells H1 and GI , I understand that there was some communication between these two wells . Communication between wells involves the flow of liquid or gas from one well to another, often across a fault line or permeable strata runningbetween the wells. This event is not an unusual occurrence when drilling top holes.

I understand as a result of information and reports I received as Rig Manager of the West Atlasthat while the 17 1/2 inch hole section was being drilled for well H1 (which is for the purpose of running the 13 3/8 inch casing), drilling mud from well H1 flowed across and through a fault linewhich runs between wells H1 and GI. The drilling mud was seen in the GI well 9 5/8 inch and 133/8 inch annulus.

I am also aware as a result of information and reports I received as Rig Manager of the West Atlas that there were reports of bubbles on GI’s 9-5/8 inch x 13-3/8 inch annulus . However,after a few days these slowed, and it was reported to me that the bubbles were either due to themud settling or that they had emanated from a small sand area above the 13 3/8 inch cement top.This was also discussed in morning meetings with PTTEPA personnel in Perth [emphasisadded.” 65

63 Commission of Inquiry Transcript, March 29, 2010, p. 131464 Commission of Inquiry Document, SEA.010.001.003865 Commission of Inquiry Document, WIT.1501.0003.0001




systems, and when cleaning operations were performed, the 20” conductor casing was installed and roughcut on H1. The West Atlas was then skidded over to the GI well, and was later taken to the H4 well, toconduct tie-in operations. Meanwhile, the H1 well was left uncapped and unattended, while the drillingstaff’s attention was focused elsewhere. 69

When the well blowout occurred, Atlas Drilling reports that plans were made to move the rig back overH1 and quickly run a RTTS 70 packer in well H1 to secure it; but, there was a delay in doing this becausethe 20” casing that had just been cut off from H4 first needed to be set down, and then the rig had to bemoved back to H1. 71 Also, the rig’s main engines were shutdown, further hindering a rapid return to H1. 72

In the end, the RTTS packer was never placed in H1, because the rig could not be moved in time.

The rush to move the rig from H1 to tie in other wells (GI and H4) left the H1 well unattended andunequipped to rapidly commence well plugging or other well intervention operations. PTTEP should nothave moved the rig from H1 to GI to H4, while a problem on H1 lingered.

PTTEP’s use of simultaneous operations to increase efficiency and reduce cost created unnecessary risk.It is not good oilfield practice to conduct well re-entry and barrier removal activities without a rig over thewell.

The West Atlas rig should have been left over H1 until the well was properly secured. The factthat the West Atlas was working on H4 when the blowout started on H1 delayed emergencyresponse actions and limited response options.

Norway’s regulations 73 require the Operator to carefully examine manning and experience. PTTEP hiredthe West Atlas crew to tie in H1. When complications arose on H1, the West Atlas rig, and the crew’sattention, was diverted to tie in GI and H4, which created inadequate manning and resources at H1. Costsavings appears to be a prime driver behind hurried rig moves and wells left in unsafe conditions in theMontara Batch Drilling Program.

Norway’s regulations at § 11 prohibit manning of tasks that are incompatible with each other.

“Section 11, Manning and competence

The party responsible shall ensure adequate manning and competence in all phases of the petroleum activities , cf. the Framework Regulations Section 10 on organisation and competence.

There shall be set minimum requirements to manning and competence in respect of functions

a) where mistakes may have serious consequences in relation to health, environment and safety ,

b) which shall reduce the probability of failures and situations of hazard and accident developing further , cf. Section 1 on risk reduction and Section 10 on work processes.

69 DA, Submission No. 4000.0001.000870 RTTS packer is a Retrievable Test Treat and Squeeze packer they work by squeezing and elastima element against the inside of the casing toform a seal, they are designed to be placed inside the casing at a deeper point in the well.71 Atlas Drilling, Submission No. 1501.0001.000672 Commission of Inquiry Document, WIT.1501.0001.006373 Petroleum Directorate Regulations Relating to Management in the Petroleum Activities (the Management Regulations), 2001.




In the manning of the various work tasks it shall be ensured that the personnel is not assigned tasks that are incompatible with each other .

The prerequisites that form the basis for the defined manning and competence, shall be followed up.

When changes in manning take place, possible consequences for health, environment and safetyshall be reviewed [emphasis added].”

The Atlas Well Control Manual states:

“While an installation is engaged in well operations, the drill floor will be manned at all times by Company employees with a minimum well control qualification required by the relevant authorized bodies in the area of operation [emphasis added].” 74

Yet, Atlas Drilling did not follow its own procedures. Atlas Drilling Manager (Mr. Gouldin) testified thatremoval of 9-5/8” PCCC, especially without a rig in place over H1, was not good oilfield practice, and if the of 9-5/8” PCCC was removed temporarily, it should have been replaced. Mr. Gouldin added that hewould not have removed it in the first place. 75

The Atlas Rig Manager (Mr. Millar) agreed that pulling off the 9-5/8” PCCC 3-4 days earlier thanplanned without well control on H1 was not a good oilfield practice. Mr. Millar testified that moving therig to another well impeded rapid well intervention on H1. Mr. Millar stated that without PCCCs in place,good oilfield practice was not followed. Mr. Millar said that 9-5/8” PCCC should have been put back on.76

The August 2009 Atlas Drilling Investigation Report concluded there was poor awareness of the risksassociated with removing barriers from a potentially live well without containment in place. 77

PTTEP Well Construction Manager (Mr. Duncan) testified that the removal of the 9-5/8” PCCC without

the rig over H1 resulted in the inability to commence rapid well intervention.78

The West Atlas rig and crew should not have left H1 uncapped, unattended, and without twopressure-tested well control barriers in place. Simultaneous high risk operations should not beconducted by the same drilling crew.

4.6 PCCC Should Have Been Replaced

PTTEP explanation as to why the 9-5/8” intermediate casing corrosion cap (PCCC) was not replacedprior to skidding the derrick to the GI well was insufficient.

“ At about 11:00pm on August 20, 2009, the ‘Montara Platform Forward Plan #1b – 20” Tieback supplementary plan was delivered to the Driller and Toolpusher on the rig floor. Thissupplementary plan detailed a diversion from the approved Montara Phase 1B Drilling &

74 Commission of Inquiry Document, SEA.009.001.075075 Commission of Inquiry Transcript, March 16, 2010, p. 5076 Commission of Inquiry Transcript, March 17, 2010, p. 19977 Commission of Inquiry Document, SEA.010.001.0008.78 Commission of Inquiry Transcript, March 16, 2010, p. 49




Completion Program Rev.0, 20” tieback batching to allow for 13-3/8” casing thread cleaning but did not require re-installation of the 9 5/8” PCCC immediately following completion of the brush job [emphasis added].” 79

In initial submittals to NOPSA and the Commission, PTTEP argued that “ seawater remained in the H1well in order to create a pressure barrier. ” Yet, during the Inquiry proceedings PTTEP acquiesced onthis point, agreeing that wellbore completion brine is not an adequate barrier to be relied upon as aprimary or secondary well control system when the rig is not in place and there is no system to monitor orcontrol the fluid system.

PTTEP Drilling Rig Supervisor (Mr. Treasure) testified th at it was a serious error to take the 9-5/8”PCCC off H1 in August and leave the well open with a suspect cementing job. 80

PTTEP Management was aware that the 9-5/8” PCCC was not set on H1 when the rig moved to GI and,later that day, to H4 to tie-in the 20” casing. 81 During Inquiry proceedings the Commission questionedPTTEP Drilling Superintendent (Mr. Wilson):

“Q. And you accept, don’t you, that the earlier removal of the 9 ‐ 5/8” PCC meant that the H1well was going to be open to the atmosphere for five or six days before the installation of a

BOP; you understand that, don’t you? A. Yes, I think at the time we didn’t think it would be five or six days; it would be a day or two days.Q. Yes, well, let’s explore that. Did you make sufficient inquiry about how many activities needed to be undertaken after the removal of the 9 ‐ 5/8” PCC so as to enable some proper risk assessment to be undertaken as to the length of time that the H1 well would remain exposed toatmosphere?

A. I don’t recall if I looked at my project timeline or not that morning, so I can’t honestly say.Q. Well, don’t you think it was a relevant consideration to factor in to any assessment about whether to reinstall the 9 ‐ 5/8” PCC or not?

A. At the time, the well had been cemented for several months. There was no pressure below thePCC, and it met our standards.Q. Sir, I’m asking you whether you now accept that in assessing whether to reinstall the 9 ‐ 5/8”PCC, a proper risk assessment would have involved a consideration of all the forward tasks so asto get some sense of how long that H1 well would be left exposed to atmosphere; do you accept that?

A. I accept that it’s part of it. However, my stance doesn’t change.Q. All right, well, do you accept that so far as, or to the extent, that’s a relevant consideration,

you didn’t look into it; that’s right, isn’t it? A. I didn’t specifically go back and look at my timeline in detail, but I knew …Q. And you thought it would be one or two days that it would be left exposed to atmosphere. Do

you now accept that, given the events that needed to occur, it was more likely to be five or six days that the H1 well would be exposed to atmosphere?

A. I don’t know that it would have been six days, but it would have been a few days, yes[emphasis added]. 82 Q. Sir, I’m not asking you about your standards. I’m just asking whether you are saying to theCommissioner, as a senior executive of PTT who’s involved in management of well integrity, that,sitting there, to this day, you say it’s okay to have a well exposed to the atmosphere for five or six

79 Commission of Inquiry Document, SEA.010.001.001980 Commission of Inquiry Transcript, March 18, 2010, p. 35681 Commission of Inquiry Transcript,. March 25, 2010, p. 959-96082 Commission of Inquiry Transcript, March 25, 2010, p. 962-963




days with only one primary barrier in place, so long as the rig is somewhere about? Now, is that your evidence? A. I guess, in light of what’s happened, no, I’d put a cap back on. Now, I have to take what’s happened into account [emphasis added].” 83

The 9-5/8” PCCC should have been immediately replaced in H1 after the 13-3/8” casing threadswere brushed.

4.7 Secure Wells During Rig Moves

Five and a half (5.5) hours after the 9-5/8” PCCC was removed [17:00 on August 20, 2009], the West Atlas was moved from H1 to the gas injection well (GI), and then later moved to producing well H4, to tiethose wells into the wellhead control system. H1 was left open to atmosphere for approximately 12 hoursprior to the blowout.

The USA requires the Operator to shut in all producible wells located in the affected wellbay below the

surface and at the wellhead when: (1) a drilling rig or related equipment is moved on or off a platform, (2)a drilling unit is moved or skidded between wells on a platform, or (3) a mobile offshore drilling unit(MODU) is moved within 500 feet of a platform. This requirement applies to rigs and related equipmentused during well-completion, well-workover, and well-decommissioning operations, in addition todrilling operations. 84 The well must be shut-in below the surface with a pump-through-type plug, and atthe surface with a closed master valve, prior to moving well-completion and well-workover rigs andrelated equipment.

Producing wells should be properly and safely secured, and pressure should be isolated, prior tomoving a rig from one well to another on an offshore platform.

4.8 Batch Drilling Increases Risk

Batch drilling and completion work increases the number of rig moves, and the number of wellinterventions, increasing risk. Leaving H1 unattended and incomplete, with the rig personnel’s attentionfocused on the GI and H4 tie-in operations, was a significant contributing factor to this incident.

The Montara Batch Drilling Program was the first batch drilling program PTTEP conducted from aWellhead Platform in Australia, and it was conducted by a Drilling Superintendent who testified that hehad no previous experience overseeing this type of batch drilling operation. 85

Originally, PTTEP planned to drill H1 from top to bottom with a BOP set for pressure control during alldrilling and completion operations. The plan was to drill and complete H1, and then tie it into a WellheadPlatform (WHP) surface wellhead control system. In this manner H1 would have had continuous pressurecontrol throughout the drilling, completion and tie-in program.

83 Commission of Inquiry Transcript, March 25, 2010, p. 96584 Notice To Lessees And Operators of Federal Oil And Gas Leases and Pipeline Right-Of-Way Holders on the Outer Continental Shelf, Gulf Of Mexico OCS Region, NTL No. 2009-G25; United States Department of the Interior Minerals Management Service Gulf of Mexico OCS Region;August 26, 2009.85 Commission of Inquiry Transcript, March 26, 2010, p. 1036




Delays in the Montara Topside Module installation caused wellhead control systems to be unavailableuntil August 2009. In response, PTTEP made a late, hurried change to the Montara well program. Thechange called for batch drilling, suspending the wells from April to August 2009, and then resuming witha batch tie-in program to the WHP when it was in place.

Increased risk associated with batch drilling and tie-in operations was not examined or mitigatedby the DA or NOPSA.

While NOPSA denies any obligation to review well control plans, its scope of authority does include theplatform facilities and safety of rig personnel, and these multiple rig moves would clearly increase risk tothose facilities and personnel.

The new batch drilling program, when compared to the original top-to-bottom drilling program,substantially increased the number of rig moves and wellbore interventions. Each rig move and wellboreintervention increases risk.

On January 6, 2009, the originally approved November 2008 drilling plan was changed to a Batch

Drilling Program for Montara wells H1, GI & H4. On February 3, 2009, the drilling program waschanged, yet again, to revise batch tie-in plans. On June 30, 2009, a final batch well tie-in program wasissued. 86

The June 30, 2009 drilling and completion program (approved by the DA) called for batching the tie-backs by casing string (a tie-in of all 20” casing on each well, then 13-3/8”, then 9-5/8”). 87

The Montara Phase 1B Drilling & Completion Program Rev.0 and the Montara Platform Forward Plan1B – 20” Tie-back Instructions (issued August 19, 2009 for the August 20, 2009 tie-in) called for the H120” tie-back activity first, followed by 20” casing tie-ins on wells GI and H1, then H4, H2 and H3. Thetie-back activity involved rough hot cutting and precision cold cutting of the 20” Casing. At 6:00am onThursday, August 20, 2009 the rig skidded over well H1 and the trash cap was removed. 88

The 9-5/8” PCCC was removed from H1 and the 13-3/8” MLS threads were cleaned with a brush toolbefore the 20” casing was tied back on H1. The 9-5/8” PCCC was not reset after the 13-3/8” MLS threadswere cleaned.

Subsequently, over the next 12hrs, the 20” Tie-Back program was undertaken on wells GI and H4. TheH4 20” casing was completed at about 5:00 am on Friday, August 21, 2009, and the 20” casing was stillhanging in the derrick at 5:30am when the H1 well blowout commenced. 89

At 5:30am Friday, August 21, 2009, the rig was retrieving the 20” tie-back cutoff from well H4 when H1kicked. 90 By 7:23am, the rig had set down the 20” tie-back and was attempting to move back over H1 tocontrol the well when the second kick occurred, requiring the rig to be evacuated. 91

When PTTEP finally came to the realization there was a very serious well control situation on H1, itdeveloped an emergency countermeasures plan. The plan was to move the rig back over H1 and run a

86 Commission of Inquiry Document, SEA.010.001.001587 Commission of Inquiry Document, SEA.010.001.000688 Commission of Inquiry Document, SEA.010.001.001789 Commission of Inquiry Document, SEA.010.001.002390 Commission of Inquiry Document, SEA.010.001.000791 Commission of Inquiry Document, SEA.010.001.0007




RTTS packer to plug the well; however, because of the delay in moving back from H4 to H1 there wasinsufficient time to set the packer.

Well H1 should have never been left open to atmosphere without a two barrier control system in place.Beginning work on the H1, disassembling what little protection systems were in place, and then movingthe rig off to tie in other wells to carry on with a batch tie-in plan, leaving H1 unattended and incomplete,with the rig personnel’s attention focused on the GI and H4 tie-in operations, was a significantcontributing factor to this incident.

It is not good oilfield practice to continue batch drilling operations if any well control or wellintegrity issues are found.

While batch drilling operations are conducted worldwide, they are not common. Batch drilling operations,if carefully planned and executed, can be completed safely. However, the increased risk associated withbatch drilling must be addressed and mitigated. Good oilfield practice requires each well to be properlysecured prior to moving to the next well.

Operators are attracted to the cost savings that can be achieved through batch drilling, especially withhigh day rates for rigs in offshore operations; however, this cost savings must be weighed againstincreased risk.

While PTTEP Management (Mr. Duncan) claimed batch drilling is a preferred drilling method from atechnical and safety standpoint, industry literature does not support this position. In a statement submittedto the Commission, Mr. Duncan said:

“…batch drilling and sequential drilling - the drilling of a well can be broken down into a seriesof tasks or operations performed in sequence. This is sometimes described as the drillingsequence of operations. There are certain points in the sequence where it is practical to interrupt the sequence of operations. For example, once a certain casing string has been set and cemented,

it is practical to interrupt the sequence. Batch drilling is where a number of wells are drilled and the sequence of operations on one well is interrupted allowing work to be has benefits includingoptimal use of drilling fluids and equipment supply. It also has a disadvantage in that interrupting the sequence of operations on one well comes at a time cost for the rig to be moved

from one well to the next . It is generally accepted that the advantages of batch drilling outweigh the disadvantages and batch drilling is preferred to sequential drilling… [emphasis added].” 92

Industry literature on batch drilling touts cost-savings as the main reason for selecting this approach, notincreased safety or reduced risk. Batch drilling allows the rig to use the same mud system, bit sizes,drilling tools and casing sizes at one time. This improves drilling efficiency, equipment handling, andlogistics, saving time and money on expensive offshore drilling operations. Yet, this also exposes theprogram to many rig moves and additional well suspension procedures, creating an elevated level of risk.

Batch drilling improves drilling efficiency, equipment handling, and logistics, which saves timeand money on expensive offshore drilling operations. Yet, this also exposes the program to manyrig moves and additional well suspension procedures, creating an elevated level of risk.

An example of how time and money were saved by batch drilling comes from Saudi Aramco, whichreports that two platforms batch drilled in the Marjan and Safaniya offshore fields saved 36 and 28 days,

92 Commission of Inquiry Document, WIT.1000.0001.0063




respectively, per platform. Batch drilling eight platforms in these same areas saved an estimated savingsof $51 million. 93

An oilfield engineering consultant, Claxton Engineering 94, advertises its services to aide companiesdevelop batch drilling programs to reduce costs. Claxton reports that use of pre-drilling and tiebacks isfinancially attractive to oil companies because wells can be drilled and ready to produce when a platformis completed bringing oil to market faster:

“ Drilling wells whilst jacket and topside structures are under construction reaps significant time and cost rewards . Once wells are tied back and completed platform production can beachieved shortly after facilities completion. Adequate planning is the key to successful tiebac k

of wells and takes care of the interface between drilling, structural and mechanical engineeringand the myriad of variations that can occur.

Pre-drilling tieback of wells can be cost effectively executed, while at the same time removing drilling activity from the project critical path . Thus mitigating interface scheduling and delayed first production risks. The key to this success is the careful evolution of historical experience, theappropriate selection of proven technological methodologies and the optimization of the process

through planning by personnel with the necessary competencies [emphasis added].”

ConocoPhillips reports that batch drilling operations “minimize cost”:

“ …it is estimated that a batch drilling program can result in potential time savings of approximately 20% over a single well at-a-time development [emphasis added].” 95

But, ConocoPhillips also reports that batch drilling processes can strain supply lines and must be carefullyplanned:

“ …the batch drilling process would consume materials at a rapid paces and supply lines would be strained [emphasis added].” 96

Elmer Danenberger (retired USA Minerals Management Official), who has more than four decades of offshore experience, wrote to the Commission that:

“ Batching and operational efficiency measures appear to have increased risks and compromised well integrity [emphasis added].” 97

A more conservative approach is to drill each well from start to finish, using an uninterruptedBOP control system. In this case, well control is transferred from the BOP stack to the wellheadcontrol systems at the final tie in.

93 Saudi Aramco Technology and Innovation, Saudi Aramco Press Release, July 6, 2008.94 www.claxtonengineering.com?Technical-Articles95 Septiantoro, A., Bujnoch, J., and Welbourne, E., ConocoPhillips Indonesia Inc. Ltd., Belanak Development: Batch Drilling Operations inNatuna Sea, SPE Paper 93820, April 2005.96 Septiantoro, A., Bujnoch, J., and Welbourne, E., ConocoPhillips Indonesia Inc. Ltd., Belanak Development: Batch Drilling Operations inNatuna Sea, SPE Paper 93820, April 2005.97 SUBM.6007.0001.0003




If batch operations are selected, safety precautions must be taken to ensure that wells are properly securedbetween each step. Wells should be secured whenever a rig operator is diverted to attend to othersimultaneous batch operations.

Norway’s regulations are very clear on this point. Section 76 of the Petroleum Safety Authority (PSA)Regulations states:

“ If a barrier fails, no other activities shall take place in the well than those intended to restore the barrier. When the wells are handed over, the status of the barriers shall be tested, verified and documented [emphasis added].” 98

Well control regulations should include a requirement similar to Norway’s PSA Well BarrierRegulation that requires sole focus on restoring well control barriers when any barrier integrityissue is found. “If a barrier fails, no other activities shall take place in the well than thoseintended to restore the barrier. When the wells are handed over, the status of the barriers shall betested, verified and documented.”

4.9

Temporary One-Barrier Systems Are Not Good Oilfield Practice

Even after the H1 well blowout, PTTEP Management testified that is reasonable to leave a well open toatmosphere for several days with one “assumed” barrier, the cemented casing shoe. During the Inquirythe Commissioner questioned PTTEP Drilling Superintendent (Mr. Wilson):

“Q. So even with the benefit of hindsight, sir, you are prepared, in effect, to say to theCommissioner and the world at large that you’re comfortable with a well remaining exposed to

atmosphere with only one permanent barrier in place, even though the rig is coming and going and might be committed on other wells for up to a period of five or six days ; is that your evidence?

A. In hindsight, which is a wonderful thing, I would have put the cap back on . But in reality,

with a well that has been cemented and in place for several months, with no pressure, noevidence of flow, that’s a situation that rigs are in a lot around the world, especially with9‐ 5/8” casing [emphasis added].” 99

This faulty logic is systemic in PTTEP’s corporate culture. PTTEP Well Construction Manager (Mr.Duncan) testified that:

“… Exposure to atmosphere is consistent with convention on surface wellhead type operationswhere allowances are made for BOP removal after cement has set as contemplated in the Atlas

Drilling Well Control Manual and commonly practised within the industry [emphasis added].” 100

PTTEP’s understanding of good oilfield practice is incorrect.

Throughout the Inquiry process PTTEP maintained it is good oilfield practice to temporarilyleave a well open to atmosphere for a period of days with only one barrier. This position is notsupported by PTTEP’s own well construction standards, international regulation, or industrystandards for what constitutes good oilfield practice.

98 Norway Petroleum Safety Authority Regulations, Section 76, Well Barriers.99 Commission of Inquiry Transcript, March 25, 2010, p. 962-963100 Commission of Inquiry Document, WIT.1000.0001.0063.




Yet, at another point when the Commissioner questioned PTTEP Well Construction Manager (Mr.Duncan) about the number of barriers that should be installed to secure a well before the rig is moved,Mr. Duncan agreed that good oilfield practice would require two barriers to be installed in H1 before therig is moved.

“Q. I want to take you back to ordinary, sensible well control practice. Do you agree that such practice does not contemplate leaving a well dependent upon only one barrier, with the derrick skidded off, for any period of time which you could accommodate by installation of a secondarybarrier?

A. Yes.Q. In other words, if you are able to install a secondary barrier, that’s what you should do?

A. Yes.Q. Quite independent of the events relating to H1 well, that's just ordinary, sensible industry

practice? A. I agree with that [emphasis added].” 101

While PTTEP’s Well Construction Manager (Mr. Duncan) claimed that he evaluated H1 casing shoeintegrity to confirm it was a properly cemented barrier before instructing rig staff to remove the 9-5/8”PCCC, 102 there is no evidence to support this assertion.

The Commission made a very good case that all H1 documents (daily drilling and cementing reports)clearly showed the H1 cement shoe had serious integrity issues and was not a competent barrier, andcertainly should not have been the single barrier relied upon for well control.

Commission counsel reiterated this same conclusion throughout the Inquiry:

“… within the four corners of that document was everything you needed to know to work out that problems with the cementing had been compounded by what was done after that and, in all likelihood, led to a wet shoe and therefore an ineffective barrier against a blowout [emphasis

added].”103

Commission proceedings reveal that the blowout most likely could have been averted if PTTEPManagement had reviewed these cementing documents and completed a proper engineering risk assessment before removing the 9-5/8” PCCC.

Atlas Drilling Manager (Mr. Millar) stated:

“A BOP was not fitted to well HI prior to the removal of the 9-5/8" PCCC as this was not possible until completion of tieback operations of the 20 inch and 13-3/8 inch casing strings. However, with the benefit of hindsight it would have been better if we had skidded the West Atlas over and continued operations on another well whilst formulating a plan to address the

missing 13-3/8 inch missing PCCC and the need to clean up the thread [emphasis added].”104

101 Commission of Inquiry transcript, April 7, 2010, p. 1502102 Commission of Inquiry Document, WIT.1000.0001.0063, p. 48103 Commission of Inquiry Transcript, April 14, 2010, p. 2165104 Commission of Inquiry Document, WIT.1501.0003.0012




The 9-5/8” PCCC should not have been removed, leaving a single barrier in H1. There was noreason that the 9-5/8” PCCC had to be removed on August 20, 2010. The 9-5/8” PCCC shouldhave remained in H1 while a technically robust and safe plan was developed to clean the 13-3/8”MLS threads. This did not require rig work to cease; the rig could have proceeded to otherMontara well tie-ins while PTTEP’s engineering and safety team devised a solution.

While DA Staff (Mr. Marozzi) testified that a three barrier standard is good oilfield practice, he did notfollow that standard by recommending approval of permits that contained a single barrier for periods of time from hours to many days:

“Q. Because your evidence is that when suspending the well, you like to see three barriers ; that'sright, isn't it?

A. Yes [emphasis added].” 105

“Q. That rather suggests that you didn't properly consider the drilling program in March last year, doesn't it , Mr. Marozzi?

A. Correct .Q. It's a failure to consider that has an important consequence, I suggest; do you agree with me? A. I agree.Q. The difference between about 2 days and about 10 to 13 days, when you are talking about

barriers to suspend a well, is not unimportant, is it ? A. Agreed .Q. That is particularly the case when there are some concerns that have been raised about the

integrity or the reliability of the primary barrier in the well to be suspended; that's right, isn't it? A. Agreed [emphasis added].” 106

“Q. But you knew that there had been problems with the float and a sudden flow from beneath the casing shoe, and so on, didn't you?

A. I was aware of that, yes. Q. And you were aware that there had been no remedial action taken; is that right? A. That's right [emphasis added].”” 107

“Q. In addition to those problems, we also have the fact that the second and third barriers,whenever they were going to be fitted, were not, to your knowledge, going to be tested and verified in situ; that's right, isn't it? A. It's compliance monitoring, that I would have expected they are done, but I do agree with you.Q. So we had the situation in which the H1 well was suspended, on your assessment and

recommendation, with not a single tested, verified barrier to prevent a blowout; that's right,isn't it? A. As it turns out, that's correct, yes.Q. That's a significant failure to comply with good regulatory practice, isn't it ?

A. Agreed [emphasis added].” 108

“Q. Do you accept that you did Mr. Whitfield a disservice in providing assistance to him in fulfilling his important role as delegate of the designated authority ?

105 Commission of Inquiry Transcripts, April 14, 2010, p. 2125 106 Commission of Inquiry Transcripts, April 14, 2010, p. 2105107 Commission of Inquiry Transcripts, April 14, 2010, p. 2112108 Commission of Inquiry Transcripts, April 14, 2010, p. 2113




A. Yes , I accept that [emphasis added].” 109

“Q. There is nothing in the drilling program, I suggest, to suggest that the pressure-containing corrosion caps referred to in the program were going to be taken off through a blowout preventer or with a production tree in place, was there? A. That's right [emphasis added].” 110

“Q. What was your understanding at the time - that is, July last year - as to how long that period would be, where the well was left with one barrier?

A. I estimated that to be between about 8 to 10 hours [emphasis added].” 111

Permit approval based on removal of secondary and tertiary barriers (even if only temporary) isinconsistent with the DA’s reported three barrier standard. Continuous, not intermittent, wellcontrol is needed.

4.10 Two-Barrier Systems Are Good Oilfield Practice

PTTEP’s submittal to the Commission lists the pressure barriers in place during the H1 suspension as:(a) a cement shoe;(b) sea water (completion brine);(c) 244mm (9-5/8”) PCCC; and(d) 508mm (20”) Trash Cap. 112

During the H1 tie-back process, the 9-5/8” PCCC and 20” trash cap were removed, leaving the cementshoe and completion brine in H1.

There was substantial debate during the testimony about whether the wellbore brine was relied upon byPTTEP as a barrier. While drilling mud connected to a mud circulation system is a well control tool, the

H1 completion brine did not serve this same purpose, and after much debate PTTEP’s Attorney (Ms.Harrison) confirmed that it was PTTEP’s position that the brine was not relied upon as a verified barrier.She stated:

“Ms. Harrison: PTTEP’s position is that it (brine) has never been relied upon as a verified barrier [emphasis added].” 113

Once there was general agreement that the H1 well completion brine was not an adequate barrier that leftthe untested, improperly cemented casing shoe as the only remaining well barrier in H1 prior to theblowout.

The seriousness of the H1 well configuration on August 20, 2009 cannot be understated. No well

should be left open to atmosphere, without surface well control, and redundant, multiple pressureisolation and/or barrier systems in place.

109 Commission of Inquiry Transcripts, April 14, 2010, p. 2114110 Commission of Inquiry Transcripts, April 14, 2010, p. 2122111 Commission of Inquiry Transcripts, April 14, 2010, p. 2122112 PTTEP, Submission No. 1000.0001.0043113 Commission of Inquiry Transcript, March 25, 2010, p. 869




On October 29, 2009, Atlas Drilling’s Consultant (Mr. Ross) issued a report that concluded thatPTTEP failed to place adequate barriers in H1:

“The main issue here is lack of adherence to the corporate barrier policy for suspending wells. As per the Report Well Suspension Summary (10th October 2009) none of the suspended wellcomply with the PTTEP barrier policy. Well H1 effectively blew out as a consequence of insufficient barriers being put in place… The reason for non compliance appears to be time

saving in placing and testing required barriers as there can be no other logical explanation [emphasis added].” 114

Prior to 2004, Australia relied on the minimum engineering standards listed in The Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production. If these standardswere used when assessing H1’s well suspension application, the DA would have required a seriesof cement plugs in the casing, meeting a minimum “two-barrier” industry well control standard,and likely averting this incident.

The revised 2004 regulations moved away from minimum prescriptive standards, instead requiring the

operator to develop a Well Operations Management Plan (WOMP) based on “good oilfield practice.” Yetthe term “good oilfield practice” has been ambiguous for industry and regulators alike.

Agency personnel were not provided technical guidance to use when making a “good oil field practice”determination. Absent guidance, many of the DAs in Australia fell back to the The Schedule of Specific

Requirements as to Offshore Petroleum Exploration and Production as the standard used for issuingpermit approvals and denials. However, the Northern Territory DA only relied on the Schedule in part,more often deferring to industry to define “good oilfield practice” on its own terms, with littlegovernment direction or intervention.

Major revisions to Australia’s regulatory regime for oil and gas operations, such as what occurred in2004, should have been coupled with a rigorous review of other international regulation regimes, to

determine the successes and pitfalls of abandoning minimum prescriptive technical standards.

Written guidance should have been issued to DA staff to define “good oil field practice,”especially for well control barriers. An issue as important as well control barriers to individualstaff discretion and interpretation.

For example, Canada’s Oil and Gas Drilling and Production Regulations require:

“WELL CONTROL35. The operator shall ensure that adequate procedures, materials and equipment are in place

and utilized to minimize the risk of loss of well control in the event of lost circulation.

36. (1) The operator shall ensure that, during all well operations, reliably operating well control equipment is installed to control kicks, prevent blow-outs and safely carry out all well activities and operations, including drilling, completion and workover operations .

114 Commission of Inquiry Document, SEA.003.015.2953




(2) After setting the surface casing, the operator shall ensure that at least two independent and tested well barriers 115 are in place during all well operations.

(3) If a barrier fails, the operator shall ensure that no other activities, other than thoseintended to restore or replace the barrier, take place in the well .

(4) The operator shall ensure that, during drilling, except when drilling under-balanced, oneof the two barriers to be maintained is the drilling fluid column.

37. The operator shall ensure that pressure control equipment associated with drilling, coiltubing, slick line and wire line operations is pressure-tested on inst allation and as often asnecessary to ensure its continued safe operation.

38. If the well control is lost or if safety, environmental protection or resource conservation is at risk, the operator shall ensure that any action necessary to rectify the situation is takenwithout delay, despite any condition to the contrary in the well approval”[emphasisadded]. 116

According to Canadian regulation at § 36(3), in the event of a failed barrier, no other activities other thanthose intended to restore or replace the barrier should take place. Diverting the West Atlas rig and crew tothe G1 and H4 wellhead tie-in jobs, leaving H1 uncapped, without a “two-barrier” system in place, was aclear breach of “good oil field practice,” according to Canadian standards.

To achieve “good oil field practice” multiple plugs should have been set downhole to create a “two-barrier” system, or a BOP with the capability of pulling the 9-5/8” PCCC through it should have beeninstalled, thereby maintaining continuous control during the well re-entry procedure.

PTTEP’s well control experts, ALERT Well Control, understand the concept of what constitutes anindustry standard “two-barrier” control system. ALERT Well Control finally secured H1 with kill mud,cement, and a two barrier plug system made up of two mechanical plugs (one set at 2,000m and a second

at 1,800m); ALERT Well Control tested the mechanical plugs in the well, and then placed a PCCC on thewell. 117

Additionally, Canada requires well completions to meet the following standards:

“WELL COMPLETION

46. (1) An operator that completes a well shall ensure that (a) it is completed in a safe manner and allows for maximum recovery;(b) except in the case of commingled production, each completion interval is isolated from

any other porous or permeable interval penetrated by the well;(c) the testing and production of any completion interval are conducted safely and do not

cause waste or pollution;(d) if applicable, sand production is controlled and does not create a safety hazard or cause

waste;

115 Whereas, “barrier” is defined in Canadian Regulation as “…any fluid, plug or seal that prevents gas or oil or any other fluid from flowingunintentionally from a well or from a formation into another formation.”116 Canada Oil and Gas Drilling and Production Regulations, effective December 2009.117 PTTEP, Submission No. 1000.0002.0025




(e) each packer is set as close as practical to the top of the completion interval and that the pressure testing of the packer to a differential pressure is greater than the maximumdifferential pressure anticipated under the production or injection conditions;

(f) if practical, any mechanical well condition that may have an adverse effect on production of oil and gas from, or the injection of fluids into, the well is corrected;

(g) the injection or production profile of the well is improved, or the completion interval of the well is changed, if it is necessary to do so to prevent waste;

(h) if different pressure and inflow characteristics of two or more pools might adverselyaffect the recovery from any of those pools, the well is operated as a single pool well or as a segregated multi-pool well;

(i) after initial completion, all barriers are tested to the maximum pressure to which they are likely to be subjected ; and

(j) following any workover, any affected barriers are pressure-tested [emphasis added].”

Furthermore, Canada requires offshore wells to be installed with an extra measure of protection once theyare completed as production wells (this holds true for Norway and the USA as well):

“SUBSURFACE SAFETY VALVE

47. (1) The operator of an offshore development well capable of flow shall ensure that the well isequipped with a fail-safe subsurface safety valve that is designed, installed, operated and tested to prevent uncontrolled well flow when it is activated [emphasis added].”

Norwegian Regulations require operators to identify the barriers required to prevent risk.

“Section 1, Risk reduction

In risk reduction as mentioned in the Framework Regulations Section 9 on principles relating torisk reduction, the party responsible shall choose technical, operational and organizationalsolutions which reduce the probability that failures and situations of hazard and accident willoccur.

In addition barriers shall be established whicha) reduce the probability that any such failures and situations of hazard and accident will

develop further,b) limit possible harm and nuisance.

Where more than one barrier is required, there shall be sufficient independence between thebarriers.

The solutions and the barriers that have the greatest risk reducing effect shall be chosen based on an individual as well as an overall evaluation. Collective protective measures shall be preferred over protective measures aimed at individuals ” [emphasis added]. 118

“Section 2, Barriers

118Norwegian Petroleum Directorate Regulations Relating to Management in the Petroleum Activities (the Management Regulations), 2001.




The operator or the one responsible for the operation of a facility, shall stipulate the strategiesand principles on which the design, use and maintenance of barriers shall be based, so that the

barrier function is ensured throughout the life time of the facility .

It shall be known what barriers have been established and which function they are intended to fulfil , cf. Section 1 on risk reduction, second paragraph, and what performance requirements have been defined in respect of the technical, operational or organisational elements which are necessary for the individual barrier to be effective.

It shall be known which barriers are not functioning or have been impaired .

The party responsible shall take necessary actions to correct or co mpensate for missing or impaired barriers [emphasis added].”

According to Norway’s regulations at § 2, the barrier function must continue uninterrupted . Clearlydiverting the West Atlas rig and crew to the G1 and H4 wellhead tie-in jobs, leaving H1 uncapped andwithout a “two-barrier” control system in place, was a clear breach of “good oil field practice.”

Norway’s Petroleum Safety Authority Regulations 119 require the following barriers and risk managementsystems to be put into place as best industry practice for preventing accidents at an offshore facility.

“Section 47, Well barriers

Well barriers shall be designed such that the well integrity is ensured and the barrier functions are working as intended in the lifespan of the well .

Well barriers shall be designed so that unintentional well influx and outflow to the external environment is prevented , and so that they do not obstruct well activities.

When a well is temporarily and permanently abandoned, the barriers shall be designed so as to

provide for well integrity for the longest period of time that the well is expected to be abandoned, inter alia so that outflow from the well or leakages to the external environment do not occur .

When a well is plugged, it shall be possible to cut the casing without harming the surroundings.

Well barriers shall be designed so that their performance can be verified [emphasis added].”

“Section 48, Well control equipment

Well control equipment shall be designed and shall be capable of being activated so as to

provide for barrier integrity as well as well control . In the case of drilling of top hole sectionswith riser or conductor, equipment with capacity to conduct shallow gas and formation fluid away from the facility until the personnel has been evacuated shall be installed.

Floating facilities shall have an alternative activation system for activating critical functions onthe blow out preventer for use in the event of evacuation.

119 Regulations Relating to Design and Outfitting of Facilities in the Petroleum Activities (“The Facilities Regulations”) of the Petroleum SafetyAuthority Norway (PSA), Norwegian Pollution Control Authority (SFT), Norwegian Social and Health Directorate (NSHD).




“ In a cased hole containing a liner string or strings, a cement plug shall be placed immediately above each liner string hanger to extend at least 30 metres above the liner string hanger. A surface cement plug extending at least 45 metres in height shall be placed in the innermost casing string which extends to the seabed with the top of the plug at a depth no greater than 45 metres below the seabed. The location and integrity of cement plugs shall be verified in an approved manner. Any intervals of cased hole in a well between cement plugs shall be filled with mud fluid of appropriate density suitably inhibited to prevent the corrosion of casing

string [emphasis added].” 120

If the prescriptive Australian standard at § 515 was still in place, as a minimum standard, wellcontrol would have been required at the surface as part of the well re-entry procedure.

Section 515 of The Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production required wells to be suspended using Section 514 (unless otherwise approved) and “ approved equipment and protection devices shall be installed on the wellhead to facilitate future re-entry of the

well .”121

There is nothing in Section 515 that says temporary suspension of an offshore well from a jack-up rig,using a mudline suspension system should only include brine in the casing and a temporary abandonmentcap on top of the casing.

Instead of following Australian Offshore Petroleum Exploration and Production standards, PTTEP:

hung the 9-5/8” intermediate casing and 13-3/8” surface casing off on the Mud Line Suspension(MLS) system; 122

left inhibited seawater in the hole (weighted brine specifications were not provided); 123

installed a corrosion cap 124 on the 9-5/8” intermediate casing; and 125

installed a trash cap 126 on the on the 20” intermediate casing. 127

PTTEP acknowledged that it did not install a corrosion cap on the 13-3/8” surface casing, 128 which wasrequired by the H1 suspension application approval. 129 However, PTTEP attributed the failure to placethe corrosion cap on the 13-3/8” surface casing to the West Atlas Drilling Supervisor. 130

PTTEP argued that placing a cement plug increased the risk of damaging 9-5/8” intermediate casing whendrilling the cement plug out. 131 Drilling out a cement plug, with a BOP in place, is a small risk in

120 The Petroleum (Submerged Lands) Act 1967, Schedule: Specific Requirements as to Offshore Petroleum Exploration and Production – 1995;November 2005 Electronic Consolidation.121 The Petroleum (Submerged Lands) Act 1967, Schedule: Specific Requirements as to Offshore Petroleum Exploration and Production – 1995;November 2005 Electronic Consolidation.122 PTTEP, Submission No. 1000.0001.0036123 PTTEP, Submission No. 1000.0001.0029124 Also commonly referred to in the oil and gas industry as temporary abandonment caps for a mudline suspension system.125 PTTEP, Submission No. 1000.0001.0036126 Cylindrical device closed on one end that fits over the conductor casing to keep debris out of the well.127 PTTEP, Submission No. 1000.0001.0036128 PTTEP, Submission No. 1000.0001.0036129 PTTEP, Submission No. 1000.0001.0037130 PTTEP, Submission No. 1000.0001.0043131 PTTEP, Submission No. 1000.0001.0045




comparison to leaving the well with no well control. Cement plugs are commonly set and drilled out; thisis a routine procedure.

PTTEP’s risk aversion to drilling out a cement plug is untenable, because this decision triggered animmediate acceptance of the catastrophic risk potential of leaving a well unsecured while it sent the rig totie-in other wells.

Atlas Drilling (Mr. Gouldin) testified that the fact that the well penetrated the hydrocarbon zone increasedthe need for a compliant temporary suspension, and that it was surprising no documentation was providedon the 13-3/8” barrier status or its compliance with the temporary well suspension permit. 132

The Commission questioned whether there should be a sign-off on installation and testing of barriers. 133

It is good oilfield practice to document barrier installation and removal.

Government of Western Australia, Department of Mines and Petroleum provided the Commission withadvice on March 5, 2010 explaining why a two barrier system is good oilfield practice:

“The cementing of casing is an inexact science especially when the casing shoe is set at 90 degrees to the vertical wellbore . There are cementing practices which are known to provide asatisfactory ‘barrier’ between the reservoir and the wellbore but there is never a guarantee that the result is 100% effective and this is the reason for the application of two physical barriers

method which does not include the hydrostatic head of wellbore fluid [emphasis added].” 134

Government of Western Australia, Department of Mines and Petroleum further advised the Commissionthat two barrier systems might include:

“ … the installation of a cement plug spotted on top of the shoe or one or more removable"packers" which are placed within the casing bore [emphasis added].” 135

Government of Western Australia, Department of Mines and Petroleum also explained to the Commissionin that same March 5, 2010 communication that it is critical to document failed cement jobs to heightenawareness of the risks and need for redundant barriers:

“In the case where a cementation fault is known or suspected … the issue is noted on the welllog and in the completion notes and appropriate secondary and or tertiary barriers are in put in

place prior to capping the well bore . That is, the drillers and others involved in the ongoing operations e.g. further drilling, completion, suspension and/or re-entry are made aware of the deficiencies prior to re-entry of the well and can take appropriate steps to mitigate the risk [emphasis added].” 136

The Victorian Department of Primary Industries provided the Commission with advice on barriers,recommending at least three (3) barriers for a long term well suspension:

132 Commission of Inquiry Transcript, March 16, 2010, p. 67133 Commission of Inquiry Transcript, March 16, 2010, p. 100 134 Commission of Inquiry Document, DMP.9000.0002.0001135 Commission of Inquiry Document, DMP.9000.0002.0002136 Commission of Inquiry Document, DMP.9000.0002.0002




“It must be noted that well integrity does not rely solely on the primary barrier. It is unwise to rely only on cemented casing as the only barrier for well integrity even if the above tests have been conducted and are accepted as confirming the calculated integrity of the cemented casing .There must be appropriate secondary barriers in place for the well at all times , particularlywhen the well is being worked on whether it is active (live) or been killed. Well integrity needs tobe considered as "a whole well approach" in that the, veil must be controlled at all time. The

petroleum industry practice in Australia is to have at least 2 barriers with appropriate highviscosity mud in its well bore if the well is suspended at the reservoir level or appropriate

mechanical barriers such as completion valves and packers are in place . The well should bekilled before suspension. Abandoned wells normally require at least 3 barriers and DPI would

treat long term suspended wells as temporary abandoned wells req uiring this number of plugs.Our earlier submission pointed to three different types of well suspensions practiced in offshoreVictorian waters. Any variation to the above would depend on the company's proposal, its risk assessment and would be treated on a case by case basis depending on the geology (reservoir aquifer conditions etc) and how the well will be managed and monitored as contained in thecompany standards or its standard operating procedures. These documents are usually listed inthe accepted WOMP and can be easily audited by the DA. 137

Other Australian DAs agree that at minimum a two barrier well control system is “good oilfieldpractice” and some even recommend three barriers for long-term well suspensions.

Atlas Drilling’s August 2009 Investigation Report concludes:

“It is accepted industry standard that to satisfy well control integrity, two independent proven barriers must be in place . It is also accepted that a hydrostatic column may also provide abarrier but this is only legitimate during drilling operations and is in addition to the minimum‘two proven barrier’ requirement [emphasis added].” 138

PTTEP’s Well Construction Standards only allow the following barriers for long-term suspension.

Pressure tested cement plug (min 30m in length) Permanent packer with no controlled internal flow path and cement on top; Cemented casing with proven TOC; Hanger packer; Tubing seals; and Annular Master Valve.” 139

PTTEP’s proposal to install a PCCC instead of a shallow set cement plug was not allowed by its ownWell Construction Standards.

Atlas Drilling states that PTTEP’s Well Construction Standards require a long-term suspended well(defined as when the drilling rig leaves the site) to have two permanent tested barriers installed in the annulus and wellbore above any hydrocarbon zone or over a pressured zone . These couldinclude: a pressure tested cement plug, permanent packer with no controlled internal flow path andcement on top, cemented casing with proven top of cement, hanger packer, tubing seals, and annular

137 Commission of Inquiry Document,DPI.0001.0002.0002138 Commission of Inquiry Document, SEA.010.001.0032139 Commission of Inquiry Document, SEA.010.001.0032




master valve. 140 There was no additional pressure tested cement plug set in the 9-5/8” intermediatecasing, no permanent packer, no evidence of cement evaluation tools to examine the top of cement inthe 9-5/8”/13-3/8”casing annulus, no hanger packer, no tubing installed seals, and no annular mastervalve installed.

Atlas Drilling’s August 2009 Investigation Report concludes:

“Well H1 was suspended with the following well control barriers in place:•Casing cement job back to and inside the 13 3/8” Casing shoe•9 5/8” Pressure Containing Corrosion Cap•Inhibited Seawater

Comparing these conditions against the standards for permanent barriers set by PTTEP (LongTerm Suspension) and subject to Safety Case inclusion , we find the following;

•There was no pressure tested cement plug inside 9 5/8” casing ;•There was no permanent packer installed ;•There was no cemented casing with a proven TOC in place (no cement bond logs were runand the existing cemented casing was assumed to have integrity based on hole volume / cement volume calculations);•There was as yet no Hanger Packer installed;•There were as yet no Tubing Seals installed; and •There was as yet no Annular Master Valve installed.”

In respect to Well H1 the requirement for two permanent tested barriers installed in the annulus and well bore above any hydrocarbon or pressured zone was therefore not satisfied [emphasis added].” 141

Mr. Duncan (PTTEP Well Construction Manager) testified that it is common to remove BOPs with justone barrier left in the well. This is not common or good oilfield practice.

If a well is batch drilled and suspended part way through the well, it is good oilfield practice to install atwo barrier system before removing the BOP. If the well is drilled from top-to-bottom and is completedwith production tubing, the standard procedure to secure the well is to install a tubing tail plug (at thebottom of the production tubing) and a tubing hanger plug (at the top of the production tubing). Theannulus is also sealed by two barriers, by a tubing packer at the base and a tubing hanger at the top. Oncethe well is secured with the tubing system and tubing plugs installed, there is a two-barrier system inplace before the BOP is removed.

Therefore either in batch drilling or drilling the well from top-to-bottom, a two barrier system should bein place before removing the BOP. If PTTEP is drilling wells without this configuration, then there maybe other wells beyond the Montara Wellhead Platform that need immediate assessment.

It is not good oilfield practice to remove barriers before a production tree or BOP is installed. Thebarriers should remain in place until the production tree or BOP is in place, establishing wellcontrol.

140 Atlas Drilling, Submission No. 1501.0001.0003 141 Commission of Inquiry Document, SEA.010.001.0033




As evidenced by Offshore Well Construction Manuals 142, barriers should be set and tested before the BOPis removed to tie the well into the wellhead control system. The plugs can be drilled out once the wellheadcontrol system is in place. This way continuous well control is maintained. It is not good oilfield practice,as Mr. Duncan (PTTEP Well Construction Manager) suggests, to remove barriers before placing a BOPor production tree.

4.11 MLS Corrosion Control

A PCCC is a metal cap threaded onto the MLS located at the well surface. Atlas Drilling Manager(Mr. Gouldin) testified that the primary purpose of a PCCC is to control corrosion, and while they canalso be designed to control pressure that is not their primary purpose. 143

The primary purpose of the PCCC, also known as a “temporary abandonment cap” or a “corrosioncap” is to prevent debris, marine growth, and corrosion from building up in the casing prior to tyingthe casing into a wellhead control system. MLS vendors recommend temporary abandonment caps tobe installed as good oilfield practice. PTTEP used a Vetco Gray Mudline Suspension System in H1.The Vetco Gray Mudline Suspension System installation manual calls for installation of a temporaryabandonment cap on each casing string. 144

Temporary abandonment MLS caps are not typically approved as pressure control barriers, but can bedesigned to also serve that purpose. 145 Vetco Gray and other vendors manufacture PCCCs that serve thepurpose of both pressure and corrosion control. Installation and removal procedures for these types of PCCCs requires substantially more precautions than a simple temporary abandonment cap that is notdesigned to serve the additional function of controlling well pressure. Use of a PCCC as a replacement fora cement plug needs careful engineering scrutiny.

PCCCs are not an adequate replacement for a shallow-set cement plug barrier, unless the PCCC ispressure rated for the maximum well pressure, is properly set and tested, and can be set andremoved through a BOP.

Testimony revealed that none of the rig crew, PTTEP contractors, regulators or PTTEP staff (except Mr.Duncan) had any experience with PCCCs that serve the purpose of both pressure and corrosion control;their experience was limited to corrosion caps that did not serve the additional pressure control function.Lack of experience with PCCCs and a lack of training on safety precautions for installation and removalof PCCCs was a contributing factor to the blowout.

When the H1 well tie-in plan was revised to use a 9-5/8” PCCC to replace a cement plug, the DAshould have required a BOP to be set and the PCCC to be pulled through the BOP to maintaincontinuous well control, and should have required the Operator to demonstrate that the staff weretrained, qualified and experienced in the use of this equipment.

142 Offshore Well Construction, University of Texas, Petroleum Extension Service Book, 2005.143 Commission of Inquiry Transcript, March 16, 2010, p. 47144 Commission of Inquiry Document, SCD.0001.0023.0167.145 Offshore Well Construction, University of Texas, First Edition, 2005.




4.12 Approved Barrier List

The January 6, 2009 Montara Batch Drilling Program required a cement plug to be set in the 9-5/8”casing, in addition to the cement shoe, with pressure testing of both barriers. The plan called for thecement plugs to remain in place until a BOP was installed on the casing. 146

The January 18, 2009 H1 well suspension plan required a cemented casing shoe at the base of the well (asthe 1 st barrier) and a 45m (148’) long, shallow-set cement plug to be set in H1 from 115m to 160m (as the2nd barrier), as well as MLS corrosion caps. 147 Installation of two cement plug barriers and MLS corrosioncaps is consistent with good oil field practice.

Atlas Drilling Management (Mr. Gouldin) testified that the normal procedure for removing a PCCC isto set a BOP and remove the PCCC through the BOP, allowing the BOP to provide well controlduring the barrier removal. 148 However, PTTEP did not follow this process, and instead removed the9-5/8” PCCC without a BOP in place, and then did not replace the 9-5/8” PCCC, leaving the wellopen to atmosphere.

Late in the day on Friday, March 6, 2009, just one day before PTTEP planned to suspend H1 for severalmonths, PTTEP requested DA approval to replace the 45m (148’) long, shallow-set cement plug with ascrew-in 9-5/8” PCCC. Removing a 45m (148’) long, shallow-set cement plug and trading it with aPCCC was not an even trade. PTTEP’s own Well Construction Standards acknowledge that PCCCs don’tprovide the same well control mechanisms as cement plugs, as evidenced by PTTEP’s list of approvedsuspension barriers, which does not include PCCCs.

Elmer Danenberger (retired USA Minerals Management Official), who has more than four decades of offshore experience, wrote to the Commission that:

“ I am not aware of any regulations, industry standards, or company manual that allow the use of a corrosion cap as a substitute for a downhole barrier [emphasis added].” 149

Yet, PTTEP’s March 11, 2009 Change Control Form concluded that the HSE impact of the removalof the H1 cement plug and replacement with a 9-5/8” PCCC would:

“…improve well integrity during suspension and re-entry operations ...” 150

Testimony and exhibits do not support this assertion. One of the major risk differences between a PCCCand a cement plug is that the PCCC needs to be removed during the tie-back, and that difference shouldhave been examined during a risk assessment.

Agency staff need clear direction on acceptable barrier types, because not all barriers are created equal.The need for direction is highlighted by the testimony of Mr. Marozzi (DA staff) who doesn’t understandthe difference in barrier effectiveness:

146 Commission of Inquiry Document, WIT.1501.0001.0005147 Commission of Inquiry Document, SEA.010.001.0010148 Commission of Inquiry. March 16, 2010 Transcript, p. 42-43149 SUBM.6007.0001.0003150 Commission of Inquiry Document, WIT.1501.0001.0180




“…Q. In those same circumstances, if an operator wished to remove a barrier operating against a blowout and replace it with a less-effective barrier, would that, in your view, in those circumstances, amount to a physical change of the wellbore? A. No .Q. Why is that?

A. I'm not sure what you mean by "less-effective barrier", but they're still acting as barriers,and the regulations are written that the operator is in the best position to select its particular equipment.Q. So is the effect of that answer that, in your mind, a barrier is a barrier is a barrier, and whatever barrier is selected by the operator won't amount to a physical change of the wellbore?

A. No, I didn't say that. The barrier has to, obviously, have suitable integrity, but all you said was"less effective". Assuming that different types of barriers are regarded as acceptable barriers and

provide integrity, then exactly which one they install - once I'm satisfied that it meets therequirements of well integrity, then it doesn't really matter which one they install . Oh, it matters,but I'm saying that the regulations are purposely non-prescriptive, which allows the operator to

make that decision, to select, test and install his own equipment [emphasis added].” 151

The Commission questioned the DA on why the previous standards found in the The Schedule of

Specific Requirements as to Offshore Petroleum Exploration and Production at Sections 514 and 515requiring cement plugs for well suspension were not followed as good oilfield practice. Mr. Marozzi(DA Staff) answered:

“…Q. If you could then look at subclauses (6) and (8), do you agree that they envisage cement plugs being used as a barrier rather than something else? A. They make reference to cement plugs - yes, (6) and (8), yes .Q. Do you agree that the specific requirements are premised upon cement plugs being used as abarrier operating against a blowout in relation to the abandonment of a well?

A. No, I don't agree with that.Q. Why not?

A. Because there's also reference to retainers and bridge plugs and packers , but you didn't

quote those.Q. Well, there's no mention of other barriers, such as pressure-containing corrosion caps, in

clause 514, is there? A. Corrosion caps is not mentioned, that's right [emphasis added]” 152

The Commission questioned the DA about the limitations of a PCCC versus a cement plug, notingthat if a PCCC is not set and pulled through a BOP it cannot act as a secondary barrier. DA staff acknowledged that they approved use of a 9-5/8” PCCC as a secondary barrier, without requiring it tobe set or pulled through a BOP. This meant there would only be one barrier in the well (cementedcasing shoe). 153

A list of approved barriers should be established in regulation and that list should be updated on aroutine basis to incorporate new technology as it is developed.

On March 12, 2009, a PTTEP Change Control Order was issued requiring a the use of 9-5/8” and 13-3/8”PCCCs on H1 in place of the planned shallow set cement plug in the bore of the 9-5/8” casing. 154 The

151 Commission of Inquiry Transcript, April 13, 2010, p. 1977152 Commission of Inquiry Transcript, April 13, 2010, p. 1982153 Commission of Inquiry Transcript, April 13, 2010, p. 2065154 Commission of Inquiry Document, SEA.010.001.0013




While PTTEP claims that corrosion developed on the 13-3/8” MLS threads during the 5-month period of abandonment, it remains unclear why the MLS threads would have become so corroded within a short 5month span of time. The 13-3/8” casing should have been designed and rated for decades of offshoreservice. Therefore, this rapid corrosion (if it did occur) raises questions about the grade, quality, and ageof the casing.

An extra 13-3/8” PCCC was shipped back to Darwin from the rig, and PTTEP logistics staff should haveimmediately realized it wasn’t installed in one of the Montara wells or should have confirmed that it wasa spare. 159 This is especially of significance because the PTTEP logistics staff spent considerable timetrying to locate the PCCCs required for the Montara Project. PTTEP testified that the manufacturer didnot have any in stock and that the logistics staff had to negotiate with other offshore operators to locatePCCCs. Therefore, logistics staff would have been aware that there were no “extra” PCCCs, and onlybarely enough PCCCs to carry out the proposed Montara well suspension plan. When an extra 13-3/8”PCCC showed up, uninstalled, in the inventory to be shipped back to Darwin, this should have soundedan “alarm bell” that a deviation from the approved well suspension plan had occurred.

Corrosion caps should be installed to prevent corrosion. Installation should be verified anddocumented as complete before the well is suspended. Government officials should inspect andaudit barrier installation, testing and removal.

No quantitative samples, videos or photographs were taken to verify the severity of the potential corrosionand/or scaling on the 13-3/8” MLS threads. Staff testimony and reports conflict on this point. Forexample, PTTEP’s own reports refer to “scale build-up” as the issue, not corrosion. 160

PTTEP’s Forward Plan August 20, 2009 for H1 states:

“Unfortunately there is some scale build-up on the 13-3/8 MLS on H1 ST1. We need to clean thisoff [emphasis added]. 161

Atlas Drilling exhibits confirmed there were no photographs taken of the “reported” 13-3/8” casing threadcorrosion. 162 Other differing accounts report rust and scale buildup. 163

PTTEP’s H1 well schematic 164 shows the 13-3/8” MLS hanger landing on the 20” internal ring hand off point, putting the 13-3/8” casing threads below sea level. The platform was in 261’ of water with an airgap of 58’ for a total of 319’ above the seabed. 165 The 9-5/8” PCCC was set in MLS at 28m (92’) belowsea level. 166 This means the 13-3/8” threads were located at least 319’ feet below the rig floor.

Additionally, Mr. Duncan (PTTEP Well Construction Manager) testified the 9-5/8” PCCC was installedthrough the BOP, 20m below the fluid level, meaning there was more than 20m (66’) of fluid above the 9-5/8” cap.

159 Commission of Inquiry Transcript, March 26, 2010, p. 996160 Commission of Inquiry Document, SEA.002.010.4096161 Commission of Inquiry Document, WIT.1501.0001.0349162 Commission of Inquiry Document, WIT.1501.0001.0006163 Commission of Inquiry Document, SEA.010.001.0018 and Commission of Inquiry Document, SEA.010.001.0006164 PTTEP Submission, SUBM.1000.0001.0011165 SEA.9000.0006.0021.166 Commission of Inquiry Document, PTT.9004.0001.0034




Surface casing : 1,637m (5,371’) of 340mm (13-3/8”) casing cemented from the casing shoeto the surface; and 177

Intermediate casing : 3,796m (12,454’) of 244mm (9-5/8”) casing cemented from the 9-5/8”casing shoe back up to the 13-3/8” casing. 178

The gas-oil contact was located at 2,609m (8,560’) True Vertical Depth (TVD). 179 Therefore intermediatecasing was set into the hydrocarbon zone.

Intermediate casing is typically set prior to drilling through the hydrocarbon-bearing zone to transitionthe surface casing to the production casing for protection of oil, gas, and freshwater zones, and to seal off anomalous pressure zones, lost circulation zones , and other drilling hazards.

PTTEP drilled through the gas-oil contact that was located at 2,609m (8,560’) TVD 180 and encounteredmajor mud losses through the Lower Johnson and Upper Puffin formations from 1,707m (5,600’). Basedon the severity of the lost circulation problems, additional strings of intermediate casing may have beenwarranted prior to drilling into the hydrocarbon zone. Multiple strings of intermediate casing arenecessary in some cases. A drilling engineer may need to set hundreds or thousands of feet of intermediate casing to: isolate unstable hole sections (to prevent collapse); isolate high or low pressurezones; isolate geologic “thief” zones prone to robbing mud from the well bore (lost circulation); put gasor saltwater zones behind pipe before drilling into the production zone; or provide additional wellborestructure.

Cementing the casing annulus across a known “thief zone,” where substantial mud losses occurred, isvery difficult because the same zone that robs mud in an overbalanced drilling situation will also robcement as it is pumped up the annulus. It is highly likely that the top of the cement was not placed behindthe 9-5/8” intermediate casing above the mud loss zone at 1,706m (5597’), and very likely that 9-5/8”/13-3/8” annular cement seal was not achieved 50m (164’) into the 13-3/8” casing shoe.

Mr. Ross’s (Atlas Drilling Consultant) October 29, 2009 report concluded that there were major drillingmud losses in H1 while drilling the 17-1/2” hole and below the 13-3/8” shoe.” 181

PTTEP’s submission verifies that the H1 9-5/8” intermediate casing shoe was not set above thehydrocarbon interval. Instead the hole was drilled to make room to set the intermediate casing cut through1,187m (3,894’) of the hydrocarbon zone, at a high angle direction. The intermediate casing was set deep,well beyond the serious reported mud losses at 1,706m (5,597’). It passed through the gas-oil contact at2,609m (8,560’) and went 1,187m (3,894’) more into the hydrocarbon zone, landing about 3m (10’)above the oil-water contact. Therefore intermediate casing penetrated the entire hydrocarbon bearingzone.

Rather than serving as a transitional casing to put the lost circulation zones at 1,706m (5,597’) behindpipe and isolate anomalous pressure zones, lost circulation zones, and other drilling hazards, theintermediate casing had to both contain the problematic lost circulation zone and serve as casing for a

long horizontal section through the pressurized hydrocarbon zone.

176 PTTEP, Submission No. 1000.0001.0034177 PTTEP, Submission No. 1000.0001.0035178 PTTEP, Submission No. 1000.0001.0036179 True vertical depth180 True vertical depth181 Commission of Inquiry Document, SEA.003.015.2951




It is very difficult to get a good cement bond over one long, continuous section of high angle intermediatecasing placed in the reservoir at a 90.3 degree angle.

The H1 casing design inherently created a high level of risk because it set a single string of intermediate casing at a high angle across a known thief zone and into a high pressurehydrocarbon bearing zone to a depth of 3,796m (12,454’). Multiple strings of intermediate casingshould have been set to isolate lost circulation zones and seal off anomalous pressure zones.

In the past decade, there has been movement toward: setting intermediate casing deeper, limiting thenumber of intermediate casings installed and/or foregoing use of intermediate casing altogether, to saveon well cost. Historically there has been a lot of latitude in well casing design, giving operators discretionas to when intermediate casing is set and how it is cemented and tested as a barrier.

PTTEP’s original public submission verified that the intermediate casing penetrated the entirehydrocarbon bearing zone. Rather than serving as a transitional casing to put the lost circulation zones at1,706m (5,597’) behind pipe, the intermediate casing had to both contain the problematic lost circulationzone and serve as casing for a long horizontal section through the pressurized hydrocarbon zone. This

casing design made the intermediate casing the production casing string . This is an important point,because there is clearly some confusion in the testimony about what standards apply to intermediatecasing, versus what standards apply when casing penetrates a hydrocarbon zone. Several of the staff assumed that the well had not penetrated the hydrocarbon zone because the term intermediate casingtypically refers to casing set above the hydrocarbon zone.

In the H1 case, because the 9-5/8” intermediate casing was not set above the production zone, and thecasing shoe was set into the hydrocarbon zone, the cement quality of the casing shoe became of criticalimportance. Instead of just formation water at the casing shoe, hydrocarbons were also present, which wasa major factor that needed to be accounted for in cementing.

Regulatory standards need to be clear about intermediate casing depth, the required number of

intermediate casing strings, and cementing and pressure testing criteria. Intermediate casingserves the important function of sealing off anomalous pressure zones, lost circulation zones, andother drilling hazards. If intermediate casing is set in the production zone, it must be treated asproduction casing and held to the same standards.

4.16 Blowout Preventer (BOP) Parking Lots

Atlas Drilling Manager (Mr. Gouldin) stated the 13-3/8” PCCC was not installed mid-March to mid-April, as planned, because it was convenient to allow the BOP to be parked on H1 from time to time.Furthermore he said that the lack of the 13-3/8” PCCC meant the lack of secondary control for the 13-3/8” by 9-5/8” annulus. 182

Mr. Treasure (PTTEP Drilling Rig Supervisor) explained that a 13-3/8” PCCC was not set because:

“… H1 was used as a temporary BOP parking lot . The Forward Plan for 7 March 2009 did not refer to the 13 3/8’’ PCCC as that would be put on at a later time as it was planned to use well

H1 as a ‘parking space’ from time to time for the BOP whilst we were working on the other wells

182 Commission of Inquiry Transcript, March 16, 2010, p. 61-62




before temporary abandonment. The BOP could not be parked on H1 if the 13 3/8’’ PCCC had been in place [emphasis added].” 183

“After the cementing operation of 7 March 2009 well H1 was taken off line. It was not practical toinstall the 13 3/8’’ PCCC straight away as the well head was going to be and was used to park the

BOP from time to time over the following weeks. I was aware that the amended DP required theinstallation of a 13 3/8’’ PCCC [emphasis added].” 184

The 13-3/8” PCCC was not installed because the 13-3/8” riser was still installed on the mudlinesuspension equipment. In an interview with NOPSA, Mr. Treasure confirmed that he could have easilyremoved the riser, but that would have increased cost because PTTEP was using H1 for BOP parkingand that resulted in quicker rigs moves. 185

March 26, 2009 (19 days after H1 was suspended) PTTEP records show at that time the H1 well was stillbeing used as a parking spot for the BOP. 186

Well H1 should not have used as a BOP parking lot. This resulted in not setting a 13-3/8 PCCC.Not only was a 13-3/8 PCCC required in the H1 well suspension plan approved by the DA, but italso was needed to secure the 9-5/8” x 13-3/8” annulus.

4.17 Blowout Preventer (BOP) and Wellhead Control Requirements

PTTEP’s plan was to re-enter H1, and then later drill out an additional horizontal production intervalbelow the intermediate casing shoe. But as a first step, PTTEP directed the West Atlas to tie all theMontara wells back into the topside wellhead control system.

A BOP should have been set for H1 re-entry because: the well had already been drilled through1,187m (3,894’) of the hydrocarbon interval; the well had known cement integrity issues; the well

had no additional cement plugs set in the casing; and the well had no other surface well controlinstalled. H1 was a “live” production well, warranting a BOP stack to be set for well re-entry.

Prior to 2004, Australia’s regulations at Section 505(7)(a) of The Schedule of Specific Requirements as toOffshore Petroleum Exploration and Production prescribed the use of BOPs:

“The blow-out prevention equipment is not removed until the well has been adequately sealed.”

Furthermore, any planned re-entries for additional drilling (such the phase 2 H1 drilling program to drillbelow the intermediate casing) would have required a BOP by Section 505(4).

Regulations need to include unequivocal BOP and wellhead control standards. The standardsshould specify when BOPs and/or wellhead control systems must be in place and when they canbe removed.

183 Commission of Inquiry Document, WIT.1000.0001.0283184 Commission of Inquiry Document, WIT.1000.0001.0287185 Commission of Inquiry Document, NOP.9000.0019.0437186 Commission of Inquiry Document, EXH.0002.0001.0001





“ Well control in horizontal wells will have to be addressed on a case by case basis . Obviously,the principles of pressure calculations and the difference between "measured depth" and "truevertical depth" are the same as in any directional well, but the potentially large influx volumes

possible in an extended reach horizontal section makes the necessity for avoiding an influx particularly keen [emphasis added].” 187

The Atlas Well Control Manual addresses control of the well while drilling and completing the well;it does not address well control when re-enteri ng a well to tie it into a wellhead platform.

Well control manuals and instructions need to address blowout control during drilling,completion and all well re-entry operations including well tie-ins. Most well control manuals andtrainings focus on well control (BOP and mud systems) while drilling and do not allocatesufficient technical guidance for rig staff on well control during batch drilling, well tie-ins andwell workovers. More instruction on these points is needed .

PTTEP was not conducting BOP tests on the required 14 day interval. By March 12, 2009, more than 21days had passed since the BOP was last tested. 188

Government inspectors are needed to witness and verify BOP testing.

4.18 Vendor Equipment Compatibility

Several vendor equipment compatibility issues arose for the H1 well, and many equipment compatibilityquestions remain unanswered. Such as: were the Apache 189 PCCCs suitable for installation in the VetcoGray Mudline Suspension System? Did possible incompatibility make installation and removal of thesePCCCs difficult or impossible? Was the Weatherford float collar compatible with the Halliburtoncementing equipment? Did this possible incompatibility contribute to the “wet” casing shoe?

There was no information in PTTEP’s submission to verify that the cement plugs and float equipmentwere compatible, and that the integrity of the shoe track (shoe and float) was checked on the platformdeck prior to running it in the hole.

Halliburton’s advertisement for its Super Seal II float collar states there has been: “ a recent rash of apparent float equipment failures .”190 Halliburton offers the industry its Super Seal II float collar andfloat shoe combination to help “…prevent re-entry of cement into the casing after displacement.” Yet, theH1 cement report shows a Weatherford float collar was used, in combination with Halliburton floatequipment and cementing plugs. 191 There was no information provided to confirm equipmentcompatibility or to explain why the Halliburton Super Seal II float collar was not selected for use.

None of the witnesses could verify whether compatibility issues were reviewed and addressed prior tousing both Weatherford and Halliburton cementing equipment in the same well.

187 Commission of Inquiry Document, SEA.009.001.0751 and SEA.009.001.0823188 Commission of Inquiry Transcript, April 7, 2010, p. 1529189 Commission of Inquiry Transcript, March 29, 2009, p. 1211190 http://www.halliburton.com/public/cem/contents/Case_Histories/web/evc/EVC_5064.asp , April 2, 2010.191 Commission of Inquiry Document, HAL.9001.0001.0383




Mr. Doeg (Halliburton Cement Staff on Rig) testified that a Halliburton wiper plug (bottom plug) and topplug and a Weatherford float collar were used. The Commission questioned Mr. Doeg about compatibilityof equipment from different manufacturers. Doeg acknowledged that incompatibility can occur andwasn’t aware of any compatibility check for the equipment used in H1. 192

Minimum standards should be set that require a thorough technical review of vendor equipmentcompatibility as part of the well construction design.

4.19 Float Collar Return Valve Failure

Even after the H1 well blowout, in the fall of 2009, PTTEP Management told NOPSA that there was noreason to suspect a problem cement job in H1. 193 Yet, the H1 cementing reports unambiguously showed awet shoe, improperly calculated cement volumes and no cement integrity verification. It was not untilmore than six months later that PTTEP admitted that the 9-5/8” casing float shoe and float collar returnvalves failed, compromising the initial 9-5/8” cement job. 194 And while DA staff acknowledged theyknew the cement shoe integrity was in question, they took no action to address it.

The H1 daily drilling and cementing reports clearly showed a failed float collar return valve, awet shoe, improperly calculated cement volumes, and no cement integrity verification. PTTEPManagement and the DA reviewed these reports, yet took no actions to address the H1 cementintegrity issues.

Casing shoe valves can fail, and when this happens remedial cementing action is required. Sometimesvalves fail because they were manufactured incorrectly, and other times valves fail because of theconditions present in the hole. For example, if the valve is subject to extended periods of circulation andhigh pressure, the valve can washout.

The March 7, 2009 Halliburton Cementing Report clearly states there was a “float failure.” PTTEP’ssubmission to the commission verifies the float collar return valve failed during the 9-5/8” intermediatecasing job. 195 A float collar is a coupling with built-in float. It is placed near the bottom of a casing stringto allow cement to flow through the casing shoe and into the annulus, while preventing the heavy cementcolumn in the annulus from flowing back into the casing. 196 However, if the valve fails, cement willbackflow into the wellbore, because the hydrostatic pressure in the annulus is greater than the pressureinside the 9-5/8” casing. If this occurs, the integrity of the cement plug at the base of the well iscompromised.

PTTEP describes the float collar configuration in H1 as:

“In the case of the H1 Well, the float collar incorporated two float valves…we had two flapper valves and a small piece of plastic pipe which held the flappers open. While that is in place, the

flappers are open and fluid can come back up through the shoe track. This is known as a self filling or auto filling float collar. A ball would normally be dropped inside the casing and whenthe ball hits the top of the hold open pipe, pressure from above causes a retaining lug to shear.

192 Commission of Inquiry Transcript, March 18, 2010, p. 449193 Commission of Inquiry Transcript,. March 25, 2010, p. 978194 PTTEP, Submission No. 1000.0001.0036195 PTTEP, Submission No. 1000.0001.0045196 International Centennial Scientific Drilling Program, http://www.icdp-online.org




The small pipe that holds the flappers open is then displaced down the hole allowing the flapper valves to shut converting the valve from auto fill to conventional one way valves.” 197

A properly cemented shoe track should be filled with cement, creating a solid cement plug at thebase of the well to prevent hydrocarbon entry into the well. If the casing shoe track is notproperly cemented, it creates a pathway for hydrocarbons to enter the well.

In this case, the float collar return valve failed, allowing cement to come back up inside the 9-5/8”intermediate casing. This cement was likely contaminated with reservoir fluids, compromising the cementbond and creating leak pathways, which are referred to as “worm-holes” in PTTEP testimony.

The March 7, 2009 PTTEP Daily Drilling Report 198 and March 7, 2009 Halliburton Cementing Report 199 both clearly state there was a “float failure.” This situation should have warranted extra concern since the9-5/8” intermediate casing was seated only 3m (10’) above the oil-water contact, putting thecompromised cement job squarely at the base of the hydrocarbon zone.

PTTEP pumped 8 barrels of mud and pressured up to 27.6 Mpa (4,000 psi) to test the 9-5/8” intermediate

casing cement shoe seal.200

When the pressure was released, 16.5 barrels of fluid returned to the surface.The fact that more volume returned than was pumped in clearly indicated that the float collar return valvefailed and a solid cement bond had not been achieved in the cement shoe track.

PTTEP reported it instructed West Atlas to hold pressure on the casing in an attempt to force the cementback through the float shoe. 201 PTTEP reported that pressure was maintained until the cement was set, andwhen pressure was bled off for the second time, no flow or differential was observed. 202 Yet, Commissiontranscripts and exhibits unmistakably show that a “wet shoe” was created in H1, compromising thepressure barrier at the base of the well. This is a fact now uncontested by PTTEP.

Because the H1 cement shoe was not completely filled with cement, a pathway for hydrocarbon flowfrom the reservoir into the 9-5/8” casing was created.

Government of Western Australia, Department of Mines and Petroleum provided the Commission withadvice on March 5, 2010:

“…if there is flow-back due to plug seating failure and/or float valve failure(even if pressure is applied until the cement has set) then it is possible that formation fluids may

have created channels in the cement behind and below the casing and therefore the integrity of the cement job should not be trusted as a barrier [emphasis added].” 203

Because the cement shoe was not a pressure tested, reliable barrier, additional barriers needed to be set inthe well. For example, a mechanical bridge plug could have been set above the cement shoe totemporarily provide a primary barrier in the well. This could have been coupled with a shallow-setcement plug in the 9-5/8” casing.

197 Commission of Inquiry Document, WIT.1000.0001.0063198 Commission of Inquiry Document, PTT.9001.0007.0346199 Commission of Inquiry Document, HAL 9002.0004.0294200 PTTEP, Submission No. 1000.0001.0045201 PTTEP, Submission No. 1000.0001.0045202 PTTEP, Submission No. 1000.0001.0045203 Commission of Inquiry Document, DMP.9000.0002.0002




A failed cement shoe itself didn’t necessarily require a cement squeeze, because the plan was to later drillthrough the cement shoe to continue the remaining production interval and set a 7” liner; it just requiredthat additional barriers be set in the well as part of the temporary abandonment process.

A mechanical bridge plug should have been set above the cement shoe to temporarily provide aprimary barrier in the well. The primary barrier should have been coupled with a shallow-set plugin the 9-5/8” casing to create a two barrier well control system.

However, as described in more detail later in this report, the lack of cement in the annulus should havetriggered a cement squeeze to properly seal off the annulus. An insufficient amount of cement in theannulus created a potential pathway for gas to flow to the surface via the annulus. Cement integrity mustalso be achieved in the annulus for well control.

A failed float collar return valve can result in insufficient annular cement volumes. Annularcement integrity should be evaluated with cement evaluation tools, and if cement integrity iscalled into question, a cement squeeze should be performed to ensure there is no pathway forhydrocarbons to move to the surface via the wellbore annulus.

Float collar return valves commonly fail, and because of this, it is good oilfield practice and standardprocedure worldwide to check to see if the float valve holds. This process typically takes 20-30 minutesof rig time; in the H1 case that equates to $14K in costs. 204

Because it is standard procedure to test whether float valves hold, it also standard procedure for drillingpersonnel (especially drilling supervisors) to know what to do if one fails. If personnel do not possess thisknowledge, they are not qualified for their position, because this is a basic step in cementing procedure.

The process for testing float collar return valves starts with rig staff carefully bleeding off pressure, toverify that the float valve holds. Then rig staff must closely monitor the volume of returned cement, andimmediately shut the well in if returns start to exceed the original amount pumped in the well to pressureup.

Testimony that claims that float valve failures are not common, and because they are not common drillingrig staff may not have the experience to know what steps to take next, is flawed. Valve failures do occur,and staff should know how to respond, or this would not be a standard step in every cementing procedure.Additionally, Operators wouldn’t spend valuable rig time to check valves unless they had a history of failure and/or serious consequences for the integrity of the cement job if failure does occur.

Float collar return valves commonly fail, and because of this, it is good oilfield practice andstandard procedure worldwide to check to see if the float valve holds.

The failure of the float valve on H1 should have raised “alarm bells” and absolutely should have triggereda series of cement checks to verify annular cement and cement shoe integrity.

Atlas Drilling Manager (Mr. Gouldin) testified that float valve failures can occur for a number of reasonsthat are not uncommon, and it is a “predictable risk.” 205

204 PTT.9001.0007.0346, $671,904 rig day rate; therefore, 30 minutes equates to $13,998.205 Commission of Inquiry Transcript, March 16, 2010, p. 53-54




Most witnesses denied any significant experience with float valve failure, citing none or only one failurein their career. Many witnesses testified they did not know what steps to take to remedy a float collarreturn valve failure. And while the PTTEP Drilling Rig Supervisor (Mr. Treasure) claimed to know howto handle a float valve failure and denied that this situation was out of reach of his competence, he couldnot even cite one specific case of float valve failure or explain the correct steps to take to remedy thesituation. 206 Other witness testimony had similar contradictions on this same point.

Industry well construction plans should provide detailed instructions on how to handle a floatcollar return valve failure.

PTTEP Management acknowledged that float collar failures are predictable risks, but it has noexplanation for why this risk was not addressed. PTTEP staff and contractors were not properly trained onhow to deal with a failed float collar return valve, nor were there written standard operating proceduresfor this scenario. 207 Mr. O’Shea (PTTEP Drilling Supervisor) is questioned by the Commissioner:

“Q. If it’s that sort of routine and predictable, it might properly be the subject of at least some treatment in the drilling program, might it not?

A. Well, we ask them - well, it states in the program to check for a float failure.

Q. Does it assist them in any way, shape or form as to how to respond to such a failure? A . Not in the program, no [emphasis added].” 208

Use of the term “check floats- Ok” in PTTEP documentation was misleading because the floats werenever OK. 209

DA Staff testified that they were aware of the failed float valves and the cementing problems, yet stillchose to allow H1 to be suspended without a shallow set cement plug. 210

Failed float collars are a known risk in the oil field and can result in a compromised cement job. Itis such a well-known risk that every well plan has a requirement to “check floats” to ensure theyare holding. Any indication of a compromised cement shoes should trigger the installation of additional well suspension barriers, because a compromised cement shoe cannot be relied upon asa barrier. A compromised cement job is also suspect in the 2010 USA Gulf of Mexico Macondowell blowout.

The PTTEP Drilling Rig Supervisor (Mr. Treasure) knew a float assembly malfunction was important andcontacted PTTEP Onshore Management (Mr. Wilson) about the problem. However, PTTEP Managementeither didn’t have a solid grasp of the significance of this problem or were more concerned aboutcontrolling costs. In either case, there was insufficient technical advice and management direction to therig crew on how to remedy the problem. 211

206 Commission of Inquiry Transcript, March 18, 2010, p. 270207 Commission of Inquiry Transcript,. March 25, 2010, p. 976208 Commission of Inquiry Transcript, March 25, 2010, p. 976209 Commission of Inquiry Transcript, March 29, 2010, p. 1185210 Commission of Inquiry Transcript, April 13, 2010, p. 2080211 Commission of Inquiry Document, NOP.9000.0019.0417




A failed float collar valve is a clear indication that a cementing integrity problem occurred.Unless steps were taken to remedy the cement job, and then verify the effectiveness of theremedial actions by additional evaluation tools, the integrity of the casing shoe cement plug at thebase of H1 should have remained a concern, and a documented risk factor, for this well.

Statistics on float valve failures are not widely available because companies don’t normally publishpapers on equipment failure; rather most technical papers advertise success cases and novel techniques.Unless there is a regulatory database auditing scheme in place, analysis of these types of cementingequipment failures is normally confined to the confidential files and databases of the Operator/vendor.

In the USA, the federal government maintains a database of offshore cementing failure statistics to assesscement failures and to make recommendations for improvements.

A Halliburton study 212 of USA Gulf of Mexico cementing failures on 4,000 wells showed that:

approximately one out of six casing shoes requires a cement squeeze job after primarycementing;

intermediate casing shoes failed shoe tests 70% more often than shallower casings, likeconductor and surface, because they are more likely to be over-displaced (the 9-5/8” casing in theMontara H1 well was intermediate casing); and

inaccurate displacement volumes are a leading cause of cement shoe failure .

Government tracking and analysis of offshore cementing failure statistics to assess cement failuretrends and successes with best available technology would assist permit approval officers,compliance officers and policymakers by providing them with the technical information neededto make informed decisions.

4.20 Failure to Comply with H1 Well Suspension Permit Conditions

Installation of a 13-3/8” PCCC was required as part of the March 12, 2009 H1 temporary well suspensionapproval. It was not installed, in violation of the approved H1 permit.

Failure to install the 13-3/8” PCCC was reported to have caused rust and scale buildup on the 13-3/8”surface casing threads, delaying H1 tie-in to the Montara Wellhead Platform control system, andcascading into a series of actions leading to a blowout.

The H1 13-3/8” PCCC was not installed, in violation of the H1 permit. This prompted a series of actions that ultimately led to the blowout.

An April 16, 2009 PTTEP email claims the Montara wells were properly suspended; however, this wasnot the case:

“Whilst we have been busy drilling some our guys have been working offline to suspend Montara H3ST-1 and Montara H1. Both wells will be fully suspended by the end of the day. This hassaved us about 12-18hrs of rig time by being able to do this activity offline – a job well done .” 213

212 Harris, K, and Grayson, G., and Langlinais, J., Obtaining Successful Shoe Tests in the Gulf of Mexico: Critical Cementing Factors, SPE paper71388, 2001.




Correspondingly, the April 16, 2009 Daily Drilling Report erroneously reported that the H1 13-3/8”PCCC was installed, when it had not been installed. The April 16, 2009 Daily Drilling Report stated:

“ Trash caps fitted to 340mm [13-3/8”] MLS and trash caps fitted to 508mm conductors on H1 and H3-ST1[emphasis added].” 214

Industry self-audits and government physical inspections and paperwork audits are needed on aroutine basis to ensure wells are constructed in accordance with permit stipulations.

DA Staff (Mr. Marozzi) testified that he was aware the 13-3/8” PCCC was not installed in early March2009, as required by the HI permit, but took no action:

“Q. Are you aware now, Mr. Marozzi, that the information provided by PTT suggests that the13-3/8" PCC was added on 16 April 2009?

A. Yes, I'm aware of that now.Q. That is, in fact, a considerable period of time after both the stage 1 and stage 2 suspensions

were approved, isn't it? A. Yes.Q. That's a very long time to have less than the three barriers you recommend or require in

relation to a suspended well, isn't it? A. Yes. Q. Despite that, you took no steps between 12 March and 16 April to raise with PTT the fact that the 13-3/8" PCC had not been added, contrary to your assumption at the time you recommended approval of the suspension; that's right, isn't it?

A. That's correct. Q. Do you think that reflected a failure on your part to carefully monitor PTT's well activities

during that period? A. Yes. [emphasis added].” 215

PTTEP Management was also aware that the 13-3/8” PCCC was not set when H1 was originallysuspended in March 2009. 216 Mr. Wilson (PTTEP Drilling Superintendent) was questioned about whyPTTEP did not immediately contact the DA when it re-entered H1 in August 2009 and found the 13-3/8”PCCC missing:

Q. Sir, do you accept that so far as the Northern Territory regulator was concerned, the H1 well,as at 20 August, had a 13-3/8" PCC in place?

A. Yes, as far as everyone was concerned it did.Q. And then you found out it didn't; that's right, isn't it?

A. Yes.Q. Did you inform the Northern Territory regulator that there was no 13 ‐ 3/8" PCC, as

required? A. I didn't call them, no, but they would have got the daily drilling report the next day, which showed that it wasn't there.Q. Did you seek their approval for the non-installation of the 13-3/8" PCC at that point?

A. No.

213 Commission of Inquiry Document,HAL.9001.0002.0217214 Commission of Inquiry Document,EXH.0001.0001.0004215 Commission of Inquiry Transcript, April 13, 2010, p. 2075216 Commission of Inquiry Transcript, March 25, 2010, p. 959-960




Q. And if, after the cleaning of the threads, the 9-5/8" PCC had been put back on and the 13- 3/8" PCC had been put on, as required, we might not be here now . A. Correct .Q. Those were decisions taken, in effect, by PTT management onshore; that's right, isn't it?

A. I certainly didn't have any discussions with the rig about reinstalling the PCC. We only talked about its removal and the cleaning of the threads. We didn't go beyond that.Q. So are you saying that you just didn't even consider the possibility of putting the H1 well in thestate that the regulator thought it would be in on 20 August; you just didn't consider the

possibility of putting on a 13-3/8" PCC, as required? A. Well, at that point, we were over the well and intervening with the well, and even with the 9-5/8" PCC removed, the well met what we thought at the time were our barrier requirements, and we didn't feel a need to put the barriers back in place. Q. So you did consider it; you just decided not to do it - is that right?

A. We were comfortable that the well met our barrier requirements , and as we were working thewell over, anyway [emphasis added]. 217

Instead of installing a 13-3/8” PCCC as required by the March 6, 2009 DA “preliminary” email approvaland the subsequent (after-the-fact) March 13, 2009 DA final written approval, PTTEP left the 13-3/8”casing above the MLS still screwed into the MLS hanger on March 8, 2009 to allow H1 to be used as aBOP parking lot while other Montara wells were batch drilled in March and April 2009. 218 PTTEPtestified that this casing was left in place as a BOP parking spot:

“This [13-3/8” casing] was left in place as a BOP parking point on the H1 well . The BOP could be landed on the 340mm (13-3/8”) braden head whilst the rig drilled top hole sections in Montara H2 & H3, wells not originally planned for when the DP was issued . This resulted inthe scheduling of the installation of the 340mm (13-3/8”)PCCC on the H1 Well for some timeafter the BOP and the MLS hanger being removed [emphasis added].” 219

Using H1 as a BOP parking spot conflicted with the H1 permit. PTTEP did not receive approval from theDA for this proposed change in H1 well barriers, nor did the DA correct PTTEP on this practice at any

time during March-April 2009.220

March 26, 2009 (19 days after H1 was suspended) PTTEP records shows one of the three 13-3/8 PCCCsneeded to finish the Montara wells (including plugging H1) was not functional. 221

“Paul you have 3 x 13-3/8 MLS pressure caps left and 1 x 9-5/8 cap left, what you need to do isremove the check value out of the 9-5/8” one and install it in the other 13-3/8’ cap as one is not

complete so we can us them on the other wells (Mat has instructions on this). [spelling errors inoriginal text; emphasis added]. 222”

One 13-3/8 PCCC was corroded 223 and was purchased from another company’s spare inventory at thelast-minute because the manufacturer was out of stock. 224

217 Commission of Inquiry Transcript, March 25, 2010, p. 959-960218 PTTEP, Submission No. 1000.0001.0063219 PTTEP, Submission No. 1000.0001.0063220 Commission of Inquiry Transcript, March 26, 2010, p. 1078221 Commission of Inquiry Document, EXH.0002.0001.0003222 Commission of Inquiry Document, EXH.0002.0001.0003223 Commission of Inquiry Document, NOP 9002.0001.0043, p. P-26224 Commission of Inquiry Transcript, April 7, 2010, p. 1647




Neither PTTEP nor Seadrill drilling personnel on-site for the suspension of well H1 could provide anyreason for the ‘missing’ 13-3/8” PCCC, nor could they provide a reason why the crew did not complywith Change Control Order No. 6. 225

And even more egregious, PTTEP prepared an as-built claiming the 13-3/8” PCCC was installed, whenin-fact it had not been. 226 Mr. Duncan (PTTEP Well Construction Manager) agreed that PTTEP did nottell the DA that the 13-3/8” PCCC was not set and that the 9-5/8” PCCC would be removed. 227 Nor did ittell the DA that the PCCCs were not pressure tested. 228

DA Staff (Mr. Marozzi) testified that they don’t inspect or audit offshore projects to ensure that theyconform to the DA’s permits:

“Q. You've done no compliance monitoring whatsoever in relation to PTT, have you, Mr. Marozzi? A. Do you mean on-site compliance monitoring?Q. I mean monitoring to ensure that they're complying with approved programs and their own

standards other than reviewing what they send you by way of information. A. Generally speaking, I admit, because we do not have a robust and rigorous compliance monitoring process, because the regulations don't require it, I do very little, yes [emphasisadded]. 229”

Government oversight (via inspections and audits) is needed to verify compliance with permitconditions.

4.21 Common Cement Failures

Typically three types of cement job failures occur: (1) lack of cement in annulus, (2) failed seal at shoe,and (3) failure to isolate formations. 230 In the H1 case, the Commission made a strong case for the lack of

cement in the annulus and a failed seal at the shoe. There is also data to support a failure to isolateformations. Thief zones behind the 9-5/8” casing may have further reduced cement placement in theannulus, because cement may have been diverted away from its intended destination.

Regulatory standards should be established to ensure there is: (1) adequate cement in the annulus,(2) the casing shoe is properly cemented (or additional barriers are set to account for a failedcasing shoe), and (3) high pressure hydrocarbon and thief zones are isolated.

4.22 Cementing High Angle Wells

The inability to initially obtain a cement seal at the base of the well (in the casing shoe track) created apathway for hydrocarbons to enter the well from the bottom. It is common knowledge in the oil and gasindustry that high angle sections of casing are notoriously difficult to cement. High angle casing strings

225 Commission of Inquiry Document, SEA.010.001.0015226 PTTEP, Submission No. 1000.0001.0063227 Commission of Inquiry Transcript, March 30, 2010, p. 1348228 Commission of Inquiry Document, WIT.1000.0001.0063, p.61 229 Commission of Inquiry Transcript, April 14, 2010, p. 2184230 Offshore Well Construction, University of Texas, First Edition, 2005.




often require additional remedial cementing treatment, careful evaluation, and intervention if a cementseal is not initially obtained. The H1 9-5/8” casing was run at 90.3 degrees into the reservoir. 231

It is true, as PTTEP pointed out, that cement evaluation logs need to be run drill-pipe conveyed in ahorizontal well, taking additional rig time. However, it is good oilfield practice to examine cement jobs todetermine if remedial work must be performed. Therefore if a horizontal well is planned, this should befactored in to the expected cost for the well.

After an initially failed cement job, there was no indication that any quality control or quality assuranceprocedures were taken to verify the remedial actions on the cementing were successful. In addition toaddressing the failed casing shoe float valve, PTTEP should have also questioned the quality of thecement job behind the pipe (annulus) in the high angle section of the well.

High angle sections of casing are notoriously difficult to cement. High angle casing strings oftenrequire additional remedial cementing treatment, careful evaluation, and intervention if a cementseal is not initially obtained.

In response to a request from Mr. Doeg (Halliburton) for expert assistance on H1 cementing, Mr. Geste(Halliburton) wrote to his colleague that:

“ Strangely enough we don’t actually have a document on setting plugs in a horizontal hole but I’m searching for one as it would seem quite important wouldn’t you say?[emphasis added]” 232

Mr. Gouldin (Atlas Management) testified that cementing horizontal wells is very difficult, and agreedthat this is another reason a cement shoe plug in the horizontal section of the well should not be reliedupon as one of the barriers by principle. 233

Because cement plugs placed in high angle sections of casing are notoriously difficult to cement,a three barrier system should be required for this type of system, setting two additional plugs

above the high angle well section to ensure well control.

4.23 Cementing the Hydrocarbon Zone

Good oilfield practice calls for placing cement in the annulus to ensure that the entire hydrocarboninterval is cemented off from the top of the reservoir to the base of the reservoir. Additionally, cementshould be placed above the top of the reservoir to ensure hydrocarbons do not channel up the annulus.

The DA approved well plan called for cement 69 m (226’) above the top of reservoir. 234 Yet, theamount of tail cement was incorrectly computed because inaccurate well depths were used byHalliburton to compute the amount of cement required. 235 Rig Supervisor secondary checks oncement volume perpetuated the error, and PTTEP Management, although specifically asked to helpQA/QC the cement volumes by the rig staff, did not provide the requested assistance. 236

231 Commission of Inquiry Document, SEA.010.001.0015232 Commission of Inquiry Transcript, March 19, 2010, p. 416233 Commission of Inquiry Transcript, March 17, 2010, p. 174234 Commission of Inquiry Transcript, March 26, 2010, p. 1006235 Commission of Inquiry Document, WIT.1000.0001.0063, p. 54236 Commission of Inquiry Transcript, March 26, 2010, p. 1010




There was no evidence provided to the Commission that a caliper log was completed to determine the 12-1/4” by 9-5/8” annular volume. Caliper logs are needed to properly estimate annular cement volumes.Atlas Drilling’s expert (Mr. Ross) also searched for evidence of a caliper log and did not find it as part of Atlas’s investigation. 237 The lack of a caliper log led to underestimated cement volumes.

It is good oilfield practice to provide for a 10% variation in average hole size when calculating open holeexcess volumes for the design of casing cementation, especially when sandstones and other permeableformations are involved. 238 In the case of Montara Platform, there were a number of recorded indicators(e.g. major losses encountered in Lower Johnson and upper Puffin zones from 1706.5m) suggestingunpredictability in the formation through which the 9-5/8” casing was set. 239

The fact that no one checked the cement volumes after the failed cement job, and only thought to do itlater in August 2009, after the blowout, is very concerning, because the cement volume would be one of the key ingredients in a QA/QC examination. Normally when there is a problem on a well, there is a“lesson learned” process where the drilling engineer goes back and tries to identify what went wrong.Was the cementing equipment faulty? Was the cement job designed incorrectly? And if so, how does thisaffect other jobs in the batch drilling program? It is good oilfield practice for the drilling engineer todiagnose what when wrong, so that the same problem is not duplicated in future wells. This is especiallytrue for a batch drilling program where well designs may be similar. Usually these lessons learned areshared with the well team in the next morning meeting, or as soon as the engineer’s analysis is ready.

Cement volume calculations must be based on accurate as-built casing depths and caliper data,and must be subject to QA/QC by the drilling engineer assigned to the project. The Operator andgovernment officials should also QA/QC and audit cementing installation.

PTTEP Management agreed that the lack of annular cement was inconsistent with the DA approvedWOMP. 240 However, PTTEP did not alert the DA to this issue, nor did the DA identify this problem. BothPTTEP and the DA lacked adequate cement QA/QC and auditing procedures.

On September 20, 2009, after the H1 blowout, PTTEP realized it did not place a sufficient amount of cement in the annulus to cover the hydrocarbon zone. The hydrocarbon top of reservoir was 2934m MDand cement was only placed to 3236m MD in the annulus, leaving 302 m (988’) of exposed hydrocarboninterval for annual flow. PTTEP internal correspondence stated:

“Top reservoir (gas cap) in Montara-H1 ST1 was at 2934.5m MD… We only put [cement] tail to 3236m. Not looking good …Well that has made my day (and yours no doubt!). Do I resign today or wait till tomorrow [emphasis added].” 241

Additionally, communication later in the day on September 20, 2009 shows PTTEP Managementacknowledged that PTTEP Management onshore was not properly quality controlling the H1 cement job.

“We issued a change control stating that the TOC needed to be X metres above the top of thereservoir for ‘well control reasons’. This was not followed by the rig and obviously not followed up by me either [emphasis added].” 242

237 Commission of Inquiry Document, SEA.001.006.4674238 TMCR-MON-B-150-00001 Rev 2 - Montara Batch Drilling Program, Section 4.3239 Commission of Inquiry Document, SEA.010.001.0036.240 Commission of Inquiry Transcript, March 26, 2010, p. 1021241 Commission of Inquiry Document, PTT.9002.0107.0379242 Commission of Inquiry Document, PTT.9003.0080.0048




During the Commission hearings PTTEP Management confirmed that there should have been 199 bbls of tail cement placed in the annulus, yet only 132 bbls were placed. 243

Good oilfield practice includes placing cement in the annulus across lost circulation zones andverifying actual cement placement depths and cement bond integrity prior to removing the BOPand moving the rig off the well.

Atlas Drilling Manager (Mr. Gouldin) stated it is important to properly cement the 13-3/8” by 9-5/8”annulus to prevent hydrocarbons from traveling up the annulus. 244 Yet, H1 records show that the top of the reservoir was at 2582m and the top of the cement was actually at 2643m, 61m below the top of thereservoir. Cement should have been placed 69m above the top of the reservoir, but it ended up 61mbelow the top of the reservoir. 245 This left a 130m gap in cement in the annulus at the top of thehydrocarbon reservoir. 246

H1 records show that the total well depth is 3796m MD; the 13-3/8” shoe was set at 1631m MD; the 9-5/8” x 13-3/8” cement in annulus went up to 1572m MD, 59m above the 13-3/8” shoe set at 1631m MD.However, the 59m of cement was short of PTTEP well construction standards that call for 150m. 247 This

left a 91m gap in cement in the 9-5/8” by 13-3/8” annulus.

Errors in the cement volume calculation occurred because PTTEP drilled the well deeper thaninitially planned and the cement volume was not recalculated to correspond to the new depth.

Additionally, the 16.5 bbl backflow through the failed float valve exacerbated the cement shortage bydropping the planned level of cement to a point about 127’ (39m) below the 13-3/8” by 9-5/8” annulusoverlap, rather than 59m above the overlap point. 248

The WOC time for H1 is described as between 3 to 3.5 hours (1500-1830hrs). The time required toachieve compressive strength varies; however the cement contractor would normally calculate the WOCtime based on the type of cement mixture, well conditions, and laboratory tests and that design time frameshould be used to ensure a good cement bond.

For example, USA Mineral Management Service (MMS) Code of Federal Regulations (CFR) at Title 30,Part 250.422 requires pressure to be held on intermediate casing cement for 12 hours. One acceptablemethod of holding cement under pressure for that 12 hour period is the use of float valves to hold thecement in place, but if they are not holding then other measures must be undertaken to hold the cement.

Minimum Wait on Cement (WOC) standards should be established to ensure cement reaches itsmaximum compressive strength prior to pressure testing it as a barrier.

243 Commission of Inquiry Transcript, March 25, 2010, p. 950244 Commission of Inquiry Transcript, March 16, 2010, p. 72245 Commission of Inquiry Transcript, March 16, 2010, p. 57246 Commission of Inquiry Document, PTT.9002.0051.0222247 Commission of Inquiry Transcript, March 16, 2010, p. 57248 Commission of Inquiry Document, SEA.003.012.2819




4.24 Cement Overdisplacement “Wet Shoe”

The Commission made an excellent case during the proceedings that the H1 casing shoe wasoverdisplaced, creating a “wet shoe” and poor cement integrity, thereby, causing the casing shoe to be anineffective barrier. 249

Atlas Drilling Manager (Mr. Gouldin) stated 9.25 bbls were used to pressure up the cement shoe; 7.25bbls flowed back when the pressure was relieved. 7.25 bbls should have been pumped back in a secondtime to pressure back up after it was clear that the float valve failed, not 16.5 bbls. Pressuring up a secondtime with 16.5 bbls created a “wet shoe.” 250

Pumping contaminated cement back into the casing shoe caused a poor cement bond in thecement shoe, creating a pathway for hydrocarbons to transit from the reservoir to the inside of the9-5/8” casing.

PTTEP Management points the finger at rig personnel for the “wet shoe;” they take no responsibility for

failure to quality control the cement job or require remedial cementing before suspending H1.251

TheCommission made the case that all the information needed to make a determination of a “wet shoe” wasright in front of PTTEP Management (and the DA for that matter), and all they had to do was read the H1Daily Drilling and Cement Reports to verify the problem.

Mr. Duncan (PTTEP Well Construction Manager) agreed the cement shoe was overdisplaced (“wetshoe”) and he agreed a basic QA/QC by onshore staff of the Daily Drilling and Cement Reports wouldhave shown that. 252

Good oilfield practice requires additional barriers to be set above a wet shoe prior to suspending awell. A “wet shoe” cannot be relied upon as a well control barrier because it creates a potentialpathway for hydrocarbons to reach the surface.

4.25 Cement Evaluation

Cement Evaluation Tools (CET) and Cement Bond Logs (CBL) are industry standard tools for evaluatingcement integrity. Running these logs can be costly in high angle wells because they must be run drill-pipeconveyed, increasing the logging time. A full suite of cement logs can take a day to run, and on anoffshore rig that cost can mount to more than $500K. 253 Some companies chose not to run cementevaluation tools to save cost.

Halliburton’s summarized its customer’s concern about cement evaluation cost:

“ Because of increasing rig rates, the costs associated with the cement bond evaluation are now subject to scrutiny . Traditionally, the cost of the services and interpretation were linked to thevalue of the information provided, i.e. the quality of data gathered was directly related to thenecessity of zonal isolation. The daily rig cost must now be considered, specifically costs directly

249 Commission of Inquiry Document, SEA.9000.0006.0021250 Commission of Inquiry Transcript, March 16, 2010, p. 75251 Commission of Inquiry Transcript, March 25, 2010, p. 944252 Commission of Inquiry Transcript, March 29, 2010, p. 1334253 when log cost and rig time is included.




related to the operating time required to the cement evaluation data . The costs of operating rig time is often an order of magnitude higher than that of the cement bond logging service and should be a critical factor in the determination of the service provider and the type of equipment run [emphasis added].” 254

Halliburton reported it has developed new cement evaluation tools that speed up logging time and reducecost:

“The new ultrasonic tools increase the logging speed up to five times, significantly reducinglogging time, rig time and costs [emphasis added].” 255

Although the cost of cement evaluation is expensive in high angle wells, this wellbore configuration isnotoriously difficult to cement, and therefore justifies the need for evaluation. It is good oilfield practiceto pressure test and run cement evaluation logs in wells where the risks and consequences of poorcementing practices are unacceptable.

Atlas Drilling Manager (Mr. Gouldin) testified that pressure tests and cement bond logs should have beencompleted to verify cement integrity. 256

Halliburton summarized the consequences of improper cementing for its customers:

“Consequences of Failures. While casing cementing equipment may be only one small expense inthe complex drilling and completion process required to construct a productive, profitable oil or gas well, the potential consequences for selecting the wrong casing cementing tool, orimproperly using the right one, can range from the cost of corrective action to the completeloss of the well [emphasis added].” 257

Halliburton recommends running a combination CBL and rotating ultrasonic tool (CAST-V) in tandembecause the two different cement evaluation tools complement each other to provide a complete zonalisolation study. Together these tools detect channels in the cement and identify the orientation of those

channels, providing detailed information for remedial cement squeeze operations.258

Cement evaluation logs should be run in wells where the risks and consequences of poorcementing practices are unacceptable.

PTTEP’s Well Construction Standards plainly state that rig personnel must verify a proven Top of Cement (TOC). 259 Yet, Mr. Ross’s (Atlas Drilling Consultant) October 29, 2009 report concluded thatPTTEP failed to run cement evaluation logs to verify TOC and cement integrity:

“In view of the problem with gas communication to surface observed on GI, running such a logto evaluate 9 5/8” cement job quality would have been useful before embarking on more similar type cement jobs… no log verification was conducted at any stage [emphasis added].” 260

254 http://www.halliburton.com/public/news/source_files/newsletters/KCNews/2005255 Shook, E., Frisch, G, (Halliburton) and Lewis, T. (Centurion Exploration), Cement Bond Evaluation, SPE 108415, March 2008.256 Commission of Inquiry Transcript, March 16, 2010, p. 75.257Shook, E., Frisch, G, (Halliburton) and Lewis, T. (Centurion Exploration), Cement Bond Evaluation, SPE 108415, March 2008.258 Frisch, G (Halliburton), O’Mahoney, L. (Chevron), Mandal, B. (Halliburton), Examination of Cement and Casing Evaluation Logs, a FieldStudy, IADC/SPE 77212, September 2002.259 Commission of Inquiry Transcript, March 19, 2010, p. 394260 Commission of Inquiry Document, SEA.003.015.2953




Mr. Duncan (PTTEP Well Construction Manager) was questioned by the Commissioner about the use of Cement Bond Logs to verify cement integrity.

Q. Log verification isn't considered a novel procedure or anything like that; it is part of theconventional armoury of well management, isn't it?

A. It is in some places. I don't think it's conducted very often in Australia.Q. What about CBL, in particular?

A. That's the one I am referring to [emphasis added]. 261

Mr. Wilson (PTTEP Drilling Superintendent) agreed that a Cement Bond Log (CBL) could have beenrun, drill-pipe conveyed, taking up to 24 hours of rig time, 262 putting t he cost of cement integrityexamination at more than $500,000.

Cement evaluation logs were not run in H1 to verify the top of cement or annular cementplacement.

Government of Western Australia, Department of Mines and Petroleum provided the Commission with

advice on March 5, 2010 explaining that a cement bond log should have been run to examine cementintegrity:

“If a cement job is considered suspect then a cement bond log may be taken to determine theadequacy of the cementing between the casing and the borehole wall [emphasis added].” 263

Mr. Geste (Halliburton Engineer) testified that a CBL and an annulus pressure test were both necessary todetermine the TOC and cement integrity. 264

The Commission requested input from the Victorian Department of Primary Industries on cementintegrity testing:

Question Posed by Commission: “ What would constitute International/Australian good oilfield practices in relation to the testing of a cemented casing shoe in circumstances where the casingshoe is in a hydrocarbon bearing zone and is to left as the primary barrier in the long-termsuspension of the well? ”

Response: “The testing of casings is guided by industry best practice (good oilfield practice) as per recommended international agencies such as API. Australia does not have such a standard or recommended guide . The closest guidance is the now revoked Clause 504 of the PSLA 1967 Schedule of Specific Requirements. The clauses in the schedule are prescriptive and wererevoked when the P(SL)(Management of Well Operations) Regulations came into force in 2004.

Even though revoked, Clauses in the Schedule are used by DPI for guidance. Clause 504 isattached. Testing of casing in reservoirs requires that the integrity of the casing and its cemented shoe track is acceptable at all times so that the casing is able to act as a first barrier to anyinvasion of formation fluids into the well bore or into the annular space between the casing and the open hole or another casing. Well integrity should be maintained at all time -whether thewell is actively worked on or suspended temporary or temporary abandoned (long term

suspension). That means that there must be well control in place at all times . In addition, other

261 Commission of Inquiry Transcript, March 30, 2010, p. 1351262 Commission of Inquiry Transcript, March 19, 2010, p. 1054263 Commission of Inquiry Document, DMP.9000.0002.0001264 Commission of Inquiry Transcript, March 19, 2010, p. 481




barriers should be placed inside the well bore and in the annular spaces above the last cemented casing shoe. The last cemented casing shoe must have adequate cement inside its shoe track and outside the casing so that the cement fills the inside of the casing shoe track as well as theannular space above the top of the reservoir. DPI uses Clause 504 as a guide which states that

the top of cement should be at least 150 metres above the top of reservoir and bottom of cement(in shoe track) is at least 30 metres [emphasis added].

If the plugs were bumped during cementing, it can be taken as the cementing process was done as per programmed. That means the volume of cement and the displacement fluids were ascalculated or estimated. Testing of the casing could be conducted almost immediately withsufficient pressure to test both the casing and the plug integrity. However, larger casing (e.g. 340mm) such as those used for surface or immediate depths, should not be tested immediately astesting creates a high tensional load (heavy load) on the casing. DPI: considers it best to test thecasing only after the cement has properly set or at least after WOC period. The casing pressuretest is normally held at the calculated pressure (about equal to the maximum burst pressure. ascalculated, which is usually less than 85% of the internal yield pressure of the casing strings) for between 20 to 30 minutes. If the pressure test failed because the float failed (plug does not hold);the casing should be tested again after the cement has set or after the WOC period (based on

samples collected during cementing). WOC could be at least 3 to 4 hours. However; it is better to test the second time after at least 12 to 24 hours to ensure that the cement has set completely .This is the most prudent thing to do and most, if not all, companies follow this principle, or

practice. The second test can be prior to drilling out the cement and casing shoe for drilling ahead into the production zone. This is normally after the BOP has been tested and installed which could take place for at least 24 hours. By then the cement is duly set . If the test failsagain, then the casing and its cement need to be repaired by such methods as squeeze cement or acement bond log (CBL) is run particularly to see the cementing of the annular space. While aCBL is useful in determining the amount of cement in the annular space, there are limitations and shortfalls with CBL. Appropriate analysis need to be conducted as compared to just casualqualitative examination of the logs. Australia does not have a prescriptive regulation

requirement for CBL log be run for every casing and cementing job but the DA can insist on

CBL as a matter of "good oilfield practice." This has been done in a number of cases in theVictorian jurisdiction. If the plugs are not bumped then there is uncertainty in the cementing

process -adequacy of the calculated volume of cement and displacement volume is uncertain. Insuch a case, testing of the casing and its cement should only be carried out after WOC or prior to drilling out the cement and casing shoe. Again, the BOP would be tested and installed by then.

If the test failed, squeeze cementing is one of the methods to repair the cement job. In this case(scenario 2) it is the same as when the plugs are bumped but the immediate pressure test failed~

Again, there is no prescriptive regulatory requirement to repair bad cementing or to conduct second casing test etc. However, these processes are normally provided for in the accepted WOMP or the drilling and completion program . Any variation to the above practices willrequire closer examination of the company's proposal and risk assessment of the proposal and this is taken on a case by case basis. In all cases, this process or procedures should be described

in the accepted WOMP or in the casing and cementing program (usually part of the drilling and completion program).” 265

Advice from the Victorian Department of Primary Industries supports the need to run cement bond logsand conduct cement squeezes. Yet this advice relies on the now revoked Section 504 of the 1967 Scheduleof Specific Requirements as to Offshore Petroleum Exploration and Production for technical guidance,clearly showing that existing Australian regulations that merely rely on a good oilfield practice standard

265 Commission of Inquiry Document, DPI.0001.0002.0001




are too vague for the government to implement. Additionally, Victorian Department of Primary Industriesclarified that there is no firm requirement to log or correct cementing deficiencies.

Regulations need to be supported with technical standards and guidance that agency staff can useto make consistent and technically sound permit decisions and to verify compliance.

Prior to 2004, Australia regulations included Section 504(4) of The Schedule of Specific Requirements asto Offshore Petroleum Exploration and Production that instructed the operator to notify the DA of anyfaulty cementing operation.

“ If there is any reason to suspect a faulty cementing operation, the Director shall be notified .”

Standard engineering text books, even those going back several decades, plainly state that cement jobsfail if any of these situations exist:

1. The cement does not fill the annulus to the required height;2. The cement does not provide a seal at the shoe; and3. Cement does not isolate hydrocarbon zones, lost circulation zones or other formations that

may pose a risk.266

Halliburton’s Cement Plug Guidelines also plainly state that common causes of plug failure include:

1. Poor written procedures;2. Incorrect temperatures;3. No allowance for contamination; and4. Poor execution. 267

The Operator should be required to notify the government of any cement integrity concerns andto explain what remedial actions and/or safeguards it has implemented.

4.26 Cement Grade

High quality cement is needed to obtain a high compressive strength bond, and prevent gas orhydrocarbons from “cutting” through the cement. During the process of setting cement, it is possible forthe well to have a hydrocarbon “kick” due to an imbalance in the density of the fluid column, ascompared to the reservoir pressure. If this occurs, it allows hydrocarbons to mix with the cement. Higherquality, higher density cement grades can be used in the design of a well to prevent this from occurring.

Prior to 2004, Australia specified cement grade and testing requirements in Section 502 of The Scheduleof Specific Requirements as to Offshore Petroleum Exploration and Production . This Section referencedAPI Specification 10 for Materials and Testing of Well Cements .

After the H1 blowout, PTTEP investigated the cement grade used. PTTEP used a standard Class Gcement. However, it should have used a high temperature cement, because the bottomhole temperatureexceeded the Class G temperature range.

266 Dowell Schlumberger, Cementing Technology, 1984.267 Commission of Inquiry Document, HAL.9002.0004.0485




Mr. Gouldin (Atlas Manager) testified that Atlas does not have good documentation procedures to track activities that do not happen on the critical path. Atlas Drilling confirmed that it does not keep records of “offline” activities; it only keeps records of items on the “critical path.” 270

PTTEP defined offline work as work that doesn’t go through the rotary table. 271

Several times there is a distinction drawn between critical path activities and “offline” activities. Normalpractice is to document all activities that affect the well at the time when they are done. A field log shouldbe maintained and transmitted to “town” (onshore offices) for a complete well file. There should not bedifferent documentation standards for activities done when the rig is on location versus when the rig is off location; all activities on the well should be documented because they cannot be committed to memorywith so many personnel involved.

Furthermore, town engineers working on the next phase of the H1 batch drilling program need to knowthe exact condition of the wells at all times. And because of the down-hole nature of well activities, if records of activities are not written down on paper, there isn’t a way to know what was and wasn’t done,as evidenced by the difficulty many witnesses had recalling information during the Inquiry.

Well records should be kept on all well activities. The logs should show what activity was completed, andwhat equipment was installed or removed. This should apply to all operations. There should not be adistinction between online and offline activities.

Precise written records must be kept on every well drilled and completed because: you cannotvisually inspect the downhole operations to reconfirm what happened at a later date; humanmemory is fallible; and rig staff changeovers is a reality of drilling operations.

Drilling staff are typically trained to keep logs so precise that essentially they could be writteninstructions for someone to use to repeat the series of actions taken and reconstruct a duplicate well fromthe log. Thus, it is not good oilfield practice to not know whether the 13-3/8” PCCC was installed. Nor is

it good oilfield practice if the logs/records are not written in a manner that is complete, such that a personat the time or at a later date could read them to know what happened.

If there is no written notation that the 13-3/8” PCCC was set, then it should be assumed that it was notinstalled. The PTTEP supervisor/engineer on the rig would normally be responsible for making sure thateach element of the well plan and permit are achieved, and should be ticking these actions off the list.This provides the check and balance needed to ensure that the work is being completed according to plan.

The DA was also getting daily drilling reports, and if it was auditing those records, it should have pickedup on the missing equipment.

Good drilling engineers and rig supervisors put their eyes on everything that goes into the hole to makesure it is the right piece of equipment, it is orientated correctly and it is in good condition, because it is theOperator that has to pay for the extra rig time to retrieve faulty or incorrectly run equipment.

270 Commission of Inquiry Document, WIT.1501.0004.0188271 Commission of Inquiry Transcript, March 17, 2010, p. 156




Normal practice is to document all activities that affect the well at the time when they are done. Afield log must be maintained and transmitted to town for a complete well file. There should not bedifferent documentation standards for activities done when the rig is on location versus when therig is off location.

4.28 Topside Installation Delay Increased Risk

Major, late changes in the Montara Platform Topside Module installation schedule, well design,and wellhead control tie-in plans contributed to hastily revised engineering and safety designplans. This was a significant contributing factor to the well blowout.

Australian regulations require numerous safety, environmental, and technical reviews to be completed byvarious agencies; yet the quality of these assessments, the level of communication between agencies, and“gaps” between regulatory jurisdictions were causal factors in this incident.

Agency submittals from the DA, 272 the National Offshore Petroleum Safety Authority (NOPSA), and theOffshore Resources Branch, Resources Division, Commonwealth Department of Resources, Energy andTourism (RET) show a lack of coordinated review.

Technical review of well completion plans, temporary well suspension plans, and re-entryprocedures was hurried, incomplete and absent of safety and environmental agency peer review.

Strong accusations were made (in particular by NOPSA) that the DA failed to conduct a proper technicalreview before issuing decisions on the H1 applications. DA testimony 273 confirmed the validity of NOPSA’s accusations; however, because NOPSA officials were not required to testify, a number of questions remain about NOPSA’s contribution to the blowout.

While NOPSA’s written submittal to the Commission lobbied for it to serve as the approving agency inthe future, NOPSA’s submittal did not explain why its safety review of the Topside Module did notidentify the delay in well control system tie-ins as a major potential well control risk. NOPSA’s safetyreview also did not identify the fact that the increase in rig moves needed to complete a batch drilling andcompletion program elevated the level of risk to the topside facility and the safety of rig personnel (forwhich NOPSA has clear responsibility). Despite recommendations that NOPSA officials be questioned onthis and other points, no one from NOPSA was called to testify before the Commission.

NOPSA’s Safety Case review did not identify the fact that the increase in rig moves needed tocomplete a batch drilling and completion program elevated the level of risk to the topside facilityand the safety of rig personnel (for which NOPSA has clear responsibility). Despiterecommendations that NOPSA officials be questioned on this and other points, no one fromNOPSA was called to testify before the Commission.

NOPSA’s submission to the Commission of Inquiry absolves itself of any oversight failures related to theH1 blowout, pointing the finger squarely at the DA. NOPSA highlighted the fact that because the DA

272 The Designated Authority (DA) for the Territory of Ashmore and Cartier Islands offshore area was delegated to the Northern TerritoryDepartment of Regional Development, Primary Industry, Fisheries and Resources (DRDPIFR), hereinafter referred to simply as “DA.”273 Commission of Inquiry Transcripts, April 12-15, 2010.




administers the Petroleum (Submerged Lands) (Management of Well Operations) Regulations 2004 , itwas the DA that reviewed and approved PTTEP’s Well Operations Management Plan (WOMP), notNOPSA.

NOPSA wrote:

“Well integrity failures, arising from inadequate design or execution of the well plan and whichwere reflected in the titleholders documented submissions and reports, could have been detected by the DA though examination of that documentation.” 274

While NOPSA denies any responsibility for oversight of subsurface activities inside the wellbore, itclearly has responsibility for surface facilities, including the topside wellhead control systems, and theoccupational health and safety of people working near them. It is also responsible for identifying howpotential surface control hazards may be interrelated to the downhole engineering of the well, andcoordinating its efforts with the DA to provide adequate agency oversight.

The Topside Module installation schedule change triggered a major change in well completion plans.Rather than drilling the well from start to finish (equipped with a blowout preventer stack the entire time),the well was only partially drilled, and then once intermediate casing was set drilling stopped. The wellwas temporarily suspended, the BOP was removed, and the H1 tie-in awaited installation of the TopsidesModule.

NOPSA did not explain what steps it took to advise the DA, RET, or DEWHA of the increased risk associated with batch drilling. Nor did it explain what steps it took to engage stakeholders in acoordinated review, or at minimum individual peer-review.

Agencies assigned to carry out oversight responsibilities should have mutual professional andtechnical respect for one another. Agencies should effectively communicate and call on eachother to provide technical assistance and peer-review. Agencies should work together to conductmulti-agency review processes that bridge potential “gaps” between regulatory jurisdictions. Lack of agency coordination materially contributed to the incident.

The Montara Wellhead Platform was made in two parts: (1) Jacket and (2) Topsides Module. The originalplan was to install the Jacket and the Topsides Module in July-August 2008. 275 The Topsides Module wasnot installed in 2008, as planned. Instead, only the Jacket was installed at the Montara field location; itwas secured in place by September 2008. 276 The Topsides Module was not installed until August 7,2009.277 Absent the Topsides Module, the wells could not be drilled and tied-in directly to the wellheadcontrol system.

This change in installation schedule triggered a major change in well completion plans. Rather thandrilling the well from start to finish (continuously equipped with a blowout preventer stack), the well wasonly partially drilled. Drilling stopped once intermediate casing was set. Wells were temporarilysuspended, awaiting installation of the Topsides Module.

274 NOPSA, Submission No. 3003.0001.0003275 PTTEP, Submission No. 1000.0001.0036276 PTTEP, Submission No. 1000.0001.0036277 PTTEP, Submission No. 1000.0001.0037




The Montara Platform Topside Module installation delay should have triggered a multi-agencysafety and environmental assessment to examine the potential risks associated with the newlyproposed batch drilling program and new Topside Module installation plans. The inability toimmediately tie newly drilled wells in to the platform wellhead control system significantlyincreased the risk factor for the Montara wells. The lack of a coordinated, peer-reviewedtechnical, safety, and environmental assessment to evaluate and identify the risks of this majordesign change appears to have contributed to the incident.

The October 2, 2009 PTTEP Montara Incident Report issued to NOPSA explained the problem with theTopside Module installation delay, and the need for multiple changes to the well construction plans over avery short period of time:

“The Jacket for the WHP facility was launched at its Montara field location on 30 June 2008 and then secured to the seabed with drilled and grouted piles during July and September 2008. The

original plan to install the topsides module for the WHP facility in July-August 2008 was aborted due to issues with contracted construction vessels. This unplanned change in theinstallation sequence resulted in the drilling programs for the Montara field development wells

being revised from their original basis of drilling and completion after WHP topsidesinstallation to the amended basis of two phases, the first phase being drilling and mud-line suspension to be carried out commencing approximately January 2009 and the second phase being continuation of drilling and completion of the wells after installation of the WHP topsides in approximately June 2009 . The West Atlas performed drilling operations for Vermilion Oil and Gas Australia Pty Ltd (“Vermilion”) and East Puffin Pty Ltd (“East Puffin”)during the last quarter of 2008 and the first quarter of 2009. In January 2009 East Puffin decided to revise its commitment to the West Atlas MODU facility with the result that PTTEPAA agreed tore-commence its utilisation of the West Atlas MODU facility in direct continuation of Vermilionrather than in direct continuation of a subsequent period of utilisation by East Puffin. Thisunplanned change resulted in PTTEPAA bringing forward the second campaign of

development wells such that the drilling programs for the Montara field were further revised so

each phase – firstly the top-hole drilling and suspension phase and secondly the horizontaldrilling and completion phase - would involve all five Montara field development wells. Prior tothe installation of the WHP topsides, the Montara field development wells where batch drilled astwo distinct batch drilling programs, The WHP topsides were installed on the jacket on 7 August 2009. On 19 August 2009 the West Atlas was positioned at the WHP facility for the purposes of commencing the horizontal drilling and completion of the Montara field development wells[emphasis added].” 278

The Drilling Plan for H1 was revised November 2008, and then again in January 2009, to incorporate thefact that the WHP Topsides would not be in place. Thus, the Montara wells were drilled to the 9-5/8”casing shoe and then were subjected to a long-term suspension while the rig left the platform during thesummer of 2009. 279 In June 2009 another drilling and completion plan was developed for H1 and theother Montara wells, to tie the them into the WHP and later drill out the production zone.

NOPSA’s last Safety Case approval for the Montara WHP was on June 16, 2009 for the Montara WHPHook-up & Pre-Commissioning. 280

278 Commission of Inquiry Document, PTT.9001.0008.0070279 Commission of Inquiry Document, WIT.1000.0001.0063, p.30280 PTTEP, Submission No. 1000.0001.0051.




An analysis should have been completed to evaluate the increased risk associated with major latechanges to the well drilling and tie-in plans, as well as the Topside Module installation delay.This work was not completed.

By comparison, Norway’s regulations 281 require the Operator to conduct a risk analysis of what affect

drilling and well activities will have on the total risk of the facilities.

Norway’s regulations read:

“Section14, Analysis of major accident risk

Quantitative risk analyses and other necessary analyses shall be carried out to identify contributors to major accident risk , including showing

a) the risk connected with planned drilling and well activities, and show which effect these activities have on the total risk on the facility ,

b) the effect of modifications and the carrying out of modifications on the total risk,

c)

the risk connected with transportation of personnel between the continental shelf and shoreand between facilities.

The analyses shall in addition be used to set conditions for operation and to classify areas,systems and equipment with respect to risk” [emphasis added].

Coordinated risk analysis and safety review required by Norway’s regulations 282 seeks a lower risk design:

“Section 4, Design of facilities

Facilities shall be based on robust and the simplest possible solutions and shall be designed so

that a) they can withstand loads as mentioned in Section 10 on loads, load effects and resistance, b) the major accident risk becomes as low as practically possible, c) failure of a component, a system or one single mistake does not lead to unacceptable

consequences ,d) the main safety functions, as mentioned in Section 6 on main safety functions, are maintained,e) transport and handling of materials can take place efficiently and safely, cf. Section 12 on

handling of materials and transport routes, access and evacuation routes, f) provision is made for a sound working environment, cf. Chapter III-II on design of work

areas and accommodation spaces,g) operational prerequisites and limitations are duly complied with,h) there are adequate provisions in place to ensure health and hygiene on board,i) provision is made for the lowest possible risk of pollution,

j) provision is made for fully satisfactory maintenance.

Measures to protect facilities against fire and explosion shall be based on a strategy.

The areas on the facility shall be classified in such way that design and location of areas and equipment contribute to reducing the risk related to fire and explosion.

281 Norwegian Petroleum Directorate Regulations Relating to Management in the Petroleum Activities (the Management Regulations), 2001.282 Norwegian Petroleum Directorate Regulations Relating to Management in the Petroleum Activities (the Management Regulations), 2001.




Areas where personnel are staying, or where equipment of significance to safety is placed, shallnot be within reach of waves with an annual probability greater than 1x10-2. [emphasis added]”

“Section 7, Safety functions

Facilities shall be equipped with necessary safety functions which at all times are able toa) detect abnormal conditions ,b) prevent abnormal conditions from developing into situations of hazard and accident ,c) limit harm in the event of accidents .

Requirements to performance shall be set in respect of safety functions.

The status of safety functions shall be available in the central control room [emphasis added].”

“Section 32, Emergency shutdown systems

Facilities shall have an emergency shutdown system which is able to prevent situations of hazard and accident from developing and to limit the consequences of accidents , cf. Section 7 on safety functions. The system shall be able to perform the intended functions independently of other systems.

The emergency shutdown system shall be designed so that it will go to or remain in a safecondition in the event of a failure which may prevent the functioning of the system. Theemergency shutdown system shall have a simple and unambiguous command structure. Thesystem shall be capable of being activated manually from release stations located at strategic

places on the facility. It shall be possible to activate functions manually from the central controlroom so that the facility is brought to a safe condition in the event of failure in the programmable

parts of the system.

Emergency shutdown valves shall be installed which are capable of stopping streams of hydrocarbons and chemicals to and from the facility, and which isolate the fire areas on the

facility [emphasis added].”

“Section 9, Plants, systems and equipment

Plants, systems and equipment shall have a design which is robust and as simple as possible, sothat a) the possibility of human errors or mistakes is limited ,b) they or it can be operated, tested and maintained without danger to personnel and with the

lowest possible pollution risk ,c) they are or it is suitable for use and capable of withstanding the loads they or it may be

subjected to during operation.

Plants, systems and equipment shall be marked in order to provide for safe operation and fullysatisfactory maintenance [emphasis added].”

The over-riding document stipulating regulatory and operational standards for the West Atlas as it workedon the Montara Platform is the Safety Case , which was reviewed and approved by NOPSA. 283 The over-

283 Commission of Inquiry Document, SEA.010.001.0028




riding document stipulating regulatory and operation standards for Montara well H1 was the WOMP,which was reviewed and approved by the DA. Yet, there was no evidence to show that NOPSA and theDA worked together to examine the entire Montara Platform Development as a whole.

None of the NOPSA Safety Case documents addressed safe well suspension and re-entry procedures. 284

March 5, 2008 Application for acceptance of Montara Facilities Construction and Installation SafetyCase, submitted December 7, 2008.

August 18, 2008 Application for acceptance of Montara WHP Hook-up & Pre-CommissioningSafety Case, submitted June 25, 2008.

November 2008 Application for Safety Case Revision for the West Atlas Rig in accordance with thePetroleum (Submerged Lands) (Management of Safety on Offshore Facilities) Regulations 1996. 285

June 16, 2009 Application for acceptance of revision 2 Montara WHP Hook-up & Pre-Commissioning Safety Case, submitted May 15, 2009.

The October 2, 2009 PTTEP Montara Incident Report issued to NOPSA explained the Safety CaseReview Process:

“The operator of the WHP facility (which includes the H1 Well) under the MOSOF Regulations isPTTEPAA. PTTEPAA’s Safety Case for the construction and installation stage in the life of theWHP facility (“WHP Construction Safety Case”) was accepted by NOPSA on 5 May 2008. Theoperator of the MODU facility under the MOSOF Regulations is Atlas. Atlas revised its NOPSA-accepted Safety Case for the MODU facility’s operations in relation to the Montara development wells, and that Safety Case Revision was accepted by NOPSA on 26 February 2008. The AtlasSafety Case together with the Atlas Safety Case Revision are hereinafter collectively referred toas the “MODU Safety Case.”

“ A revision to the WHP Construction Safety Case for the WHP facility’s hook-up and pre- commissioning phase (including for simultaneous operations (“SIMOPS”) with the MODU facility and the construction vessel facility operated by Clough (“Java Constructor”)) was accepted by NOPSA on 18 August 2008 and 16 June 2009 . A revision to the MODU Safety Case for the SIMOPS with the WHP facility and the Java Constructor, was also accepted by NOPSA.These safety case revisions detail the SIMOPS between the WHP facility and the MODU

facility, including establishing the applicable SIMOPS matrix that applies in relation to activities taking place on the WHP facility whilst the MODU facility is in position at the WHP facility. The SIMOPS matrix was formulated to ensure consistency with the SIMOPS matrix of the MODU facility as provided for in the MODU facility’s SMS. This safety case revision notes that hook-up or pre-commissioning work on the WHP facility will be carried out in accordancewith the PTTEPAA SIMOPS procedure but this incorporates restrictions on that work during

MODU operations involving cantilevering/skidding of the MODU facility’s derrick and requires the Permits to Work issued under the PTTEPAA WHP facility SMS in respect of thatwork to be counter-signed by the MODU facility’s permit authority. Relevantly, this safety caserevision also stipulates that in the event of an emergency, personnel at the WHP facility arerequired to muster in response to the MODU facility’s alarm and that the MODU facility’s OIM

284 PTTEP, Submission No. 1000.0001.0051285 Commission of Inquiry Document, PTT.9000.0009.0210




will direct those persons to either evacuate from the WHP facility or from the MODU facility withthe MODU facility being their primary means of evacuation [emphasis added].” 286

Good oilfield practice is to ensure that adequate well control plans are in place, especially if wells will bedrilled and temporarily suspended before surface facilities (wellhead control systems) are constructed.

4.29 Drilling Delay Should Have Been Considered for Risk Mitigation

If the Montara wells were drilled from top to bottom and tied into the Topside Module wellhead controlsystem as originally planned, instead of drilled in a batch drilling program, this incident would have likelybeen averted.

NOPSA and the DA should have considered delaying the drilling program until the TopsideModule was available or they should have required additional risk mitigation.

4.30

Safety Case Review Did Not Identify or Mitigate Wellhead Control System Risks

In 2005, Australia’s Safety Case regime made the rig operator legally responsible for the safety of theworkforce at a work site. While the rig operator is responsible for the safety issues associated with the rig,PTTEP is responsible for the safety issues associated with the well. There is an overlap in responsibilitiesbecause the work on the well can result in safety risks to the rig and work on the rig can result in safetyrisks to the well. Therefore compatible, complementary policies and procedures for rig and welloperations are needed. Furthermore, oversight from agencies should be closely coordinated to ensurethere are no gaps.

The November 2008 Safety Case Revision for the West Atlas rig, prepared by PTTEP and Atlas andsubmitted to NOPSA, included an examination of the risks associated with barriers and well control. 287

The risks associated with drilling three wells (2 producers, and 1 injector) from the Montara WellheadPlatform (WHP) was examined. 288 Yet, four wells (H1-H4), and one injector (GI) were actually drilled.The additional well count was not examined in the Safety Case Revision . PTTEP and Atlas’s November2008 Safety Case Revision stated:

“ At the time of preparation of this SCR the Drilling, Completions and Testing Programmes for the Campaign has not been completed [emphasis added].” 289

PTTEP and Atlas’s November 2008 Safety Case Revision stated that: the well hazards were based onthe Vulcan Basin Drilling Program, because the Montara Drilling Program was not yet completed ;a HAZID analysis was completed; no new hazards were identified; and minor modifications were made tothe barriers and controls to ensure the risk was As Low As Reasonably Practical (ALARP). 290 ALARP isa “principle that provides a means for assessing the tolerability of risk. A risk is ALARP if the cost of anyreduction in that risk is grossly disproportionate to the benefit obtained from the reduction.” 291

286 Commission of Inquiry Document, PTT.9001.0008.0070287 Commission of Inquiry Document, PTT.9000.0009.0216288 Commission of Inquiry Document, PTT.9000.0009.0218289 Commission of Inquiry Document, PTT.9000.0009.0218290 Commission of Inquiry Document, PTT.9000.0009.0224291 Commission of Inquiry Document, SUBM.1000.0002.0051




NOPSA, who is responsible for reviewing and approving the Safety Case Revision , acknowledged itslack of downhole expertise to the Commission, but at the time of Safety Case Revision approval didnot enlist any technical review from the DA or independent consultants.

The November 2008 West Atlas Drilling Rig Safety Case Revision included information on thebarrier and well control risks. However, that analysis was incomplete because the MontaraDrilling Program was not yet completed. Furthermore, NOPSA, who is responsible for reviewingand approving the Safety Case Revision , acknowledged its lack of downhole expertise to theCommission, but at the time of Safety Case Revision approval did not enlist any technical reviewfrom the DA or independent consultants.

The Safety Case Revision stated the West Atlas Well Control Manual governs well control procedures andthat: 292

“ Primary well control shall be achieved with the casing, well design, drilling programme and completions programme which comply with Coogee Resources Well Construction Standards …[and]... will be conducted in accordance with the Atlas Drilling Well Control Manual

[emphasis added].”293

The November 2008 Safety Case Revision should not have been approved by NOPSA, absentwell plans for the Montara wells drilled in early 2009. Insufficient well data and risk analysis wasincluded in the Safety Case Revision for agency decision making. The Safety Case Revision process should have been suspended until a complete set of plans was available.

The Safety Case Revision stated that the BOP would provide well control; therefore both NOPSA and theDA had a responsibility to ensure that a BOP was installed. Yet, a BOP was not installed during H1 re-entry: 294

“ Loss of well control is not recognized as an MAE in the West Atlas VSC FSA because the BOP has been assessed to provide sufficient barriers and controls .” 295

The approved Safety Case Revision was based on a BOP being put in place for well control. Yet,no BOP was installed. And to compound matters, the DA approved well plans that provided forwell re-entry and tie-in without a BOP. The Safety Case Revision identified the BOP as a criticalhealth, safety and environment (HSE) piece of equipment. Yet, the BOP was not even installed onH1 during re-entry. 296

The Safety Case Revision stated:

“ The BOP is critical in closing the well if the drilling crew lose control of formation

fluids/gases [emphasis added].”297

The lack of a BOP for H1 re-entry was inconsistent with the Safety Case Revision .

292 Commission of Inquiry Document, PTT.9000.0009.0227293 Commission of Inquiry Document, PTT.9000.0009.0228294 Commission of Inquiry Document, PTT.9000.0009.0227295 Commission of Inquiry Document, PTT.9000.0009.0227296 Commission of Inquiry Document, PTT.9000.0009.0298297 Commission of Inquiry Document, PTT.9000.0009.0298




The table below summarizes the potential H1 cost savings. These cost cutting measures, while savingPTTEP money in the short term, have resulted in major financial losses to the company as a result of having to drill a relief well and fund the oil spill cleanup.

Montara Rig Day Rate 671,904.00$ Based on Daily Drilling Report for March 7, 2009Montara Rig Hourly Rate 27,996.00$

Steps Not Taken Cost Savings Estimated Hours Description

1 701,904.00$ 24.0Pressure testing and cement evaluation logs not completed (rig time andlog cost)

2 1,207,856.00$ 36.0 Cement squeeze not completed (rig time and materials)

3 467,936.00$ 16.0Cement plug barrier not installed in 9-5/8" casing and later drill-out timeavoided (rig time and materials)

4 41,994.00$ 1.5 9-5/8" PCCC not reset (rig time)5 71,994.00$ 1.5 13-3/8" PCCC not installed (rig time and cost of PCCC)

6 559,920.00$ 20.0Rig time saved by not leaving rig at H1 to address PCCC/corrosion/wellcontrol issues and moving the rig to GI and H4 instead

7 335,952.00$ 12.0

Rig time saved by not setting 13-3/8" PCCC and using H1 as BOPparking area instead of moving BOP's to test dump (used a conservativeestimate of 1/2 day saved)

8 121,984.00$ 4.0Caliper log was not run to determine the 12-1/4” by 9-5/8” annularvolume for properly estimating annular cement volumes

9 100,000.00$ Drilling engineering support understaffed for project10 419,940.00$ 15.0 Time saved by installing 13-3/8" PCCC and 20" Trash cap offline

Total Estimated Hours 115.0Total Savings 4,029,480.00$

Potential Cost Saving for Montara H1

Without these cost savings H1 would have exceeded the $13,442,794 Authorization for Expenditure(AFE) by at least 30%.

Some of the costs in the table above were estimated based on field experience and others weredocumented in Inquiry transcripts and exhibits. For example:

Atlas Drilling testified that on March 12, 2009 PTTEP formally issued a change control order toalter the well suspension plan to leave out a cement plug and only install a 244mm (9-5/8”)intermediate casing PCCC at a cost savings of US $50,000.

Approximately, 1.5 hours of rig time was saved by not re-installing the 9-5/8” PCCC. 307

Halliburton estimated a squeeze job would take about 24 hours of rig time. 308

An April 16, 2009 PTTEP Management email communication states:“Whilst we have been busy drilling some [of] our guys have been working offline to suspend

Montara H3ST-1 and Montara H1. Both wells will be fully suspended by the end of the day.This has saved us about 12-18hrs of rig time by being able to do this activity offline – a jobwell done [emphasis added].” 309

307 Commission of Inquiry Transcript, March 19, 2010, p. 400308 Commission of Inquiry Transcript, March 19, 2010, p. 427309 Commission of Inquiry Document,HAL.9001.0002.0217




PTTEP Management acknowledged cost savings was a motivating factor for not pressure testing.PTTEP Management also acknowledged this was a factor when it elected to install barrierswithout the rig (“offline”). 310

Mr. Wilson (PTTEP Drilling Superintendent) agreed that testing cement integrity with a drill-pipeconveyed cement bond log (CBL) could have taken up to 24 hours of rig time. 311 That would put

the cost of cement integrity examination at more than $500,000. Mr. Wilson (PTTEP Drilling Superintendent) said that repeat pressure tests on the casing shoe

would have taken 20 minutes, followed by 16-18 hours that would have been needed to install abridge plug. A squeeze job would have required the shoe to be drilled out and re-cemented, takingseveral days. 312

Authorization for Expenditures (AFEs) should include sufficient funds for safety, qualityassurance and quality control (QA/QC) procedures, adequate staffing, and engineeringevaluations and risk assessments when problems are identified. Government should ensure thesecomponents are included as non-discretionary items in the approved well plan.

In 2007 Advanced Well Technologies Pty Ltd (AWT) lodged serious complaints against PTTEP’s costcutting and risk taking on the Montara Project. It was so concerned about these problems that it chose toforego revenue opportunities and discontinue its business relationship with PTTEP as a consultant. This isa very bold and serious move for a technical consultant to make, but one AWT felt was necessary in orderto spare its reputation. 313

“ I would like to inform you that unfortunately this will effectively terminate all completion services provided by AWT to Coogee.

As outlined in my email in June (copied below) we have become increasingly concerned with theway our team is managed within the Montara project. When we set out our engagement with youwe agreed that AWT would manage completions engineering on behalf of Coogee through asingle coordinator/teamleader being Arthur, and that this was on the basis of AWT takingresponsibility for Completions and not to supply ‘bodies’ or consultants requested ad-hoc. AWT

are experts at completions engineering and our reputation is based on successful management of all risks related to engineering and implementation of completion equipment design and installation, in particular in cases where complex intelligent completions are run such as is thecase for Coogee .

We have lately become concerned with a number of our team recommendations being rejected with little or no technical justification other than cost: for the type of completions Coogee is

running we consider that this has significantly increased the risk profile of the project. Anexample is the recent selection of BakerHughes control line protectors that are technicallyinferior and for which the supplier of the control lines and intelligent components(WellDynamics) will take no responsibility. Whilst this offers a modest 50K$ saving for the

project, the risk exposure this gives is substantial and in our opinion this decision has not been taken using an appropriate quantified risk assessment . The longer term functionality of thisequipment is critical to the operability of the field and for production assurance, and in our

310 Commission of Inquiry Transcript, March 26, 2010, p. 1032311 Commission of Inquiry Transcript, March 19, 2010, p. 1054312 Commission of Inquiry Transcript, March 19, 2010, p. 1054313 Commission of Inquiry Document, AWT.0001.0001.0019




considered opinion, this very modest savings does in no way justify the potential installation risk,the longer term production risk and the potential associated cost consequence.

AWT have been involved in numerous completions installations and have learned -sometimes the hard way -about the consequences of equipment failure and poor planning/design decisions, which are now significantly compounded by high day rates of rigs . We are alsoconcerned with the decision not to conduct clean-up trips ahead of running these complexcompletions, contrary to our strong recommendation…Duncan, we regret that the misalignment between Coogee and AWT has caused us to part ways and would like to assure you that this is not our preference and we have always been a strong supporter and contributor to the Montara/Skuadevelopment plan. However we are deeply concerned with potential for damage to our

professional reputation if we are to continue to be seen to be responsible for the completions design and implementation of this project whilst not able to influence (in our view) criticaldecisions. We respect that this is Coogee’s project and like all projects need a healthy cost focus,and that from time to time your management team will need to take project decisions whichbalance a variety of interests, but we believe that a failure to assess and quantify the risks

associated with such decisions will ultimately be to the detriment of the execution budget and longer term operability of the production system . [emphasis added].” 314

On September 27, 2007 Advanced Well Technologies Pty Ltd (AWT) provided a list of cost-cuttingconcerns on the Montara Project. 315

“ It is felt by all the AWT team members that unfortunately even although this is a good challenging well, and engineering project work-scope the recent, present and ongoing workingenvironment will not allow for the AWT completion team recommendations to be recognised

and will be over-ruled on a cost basis only. In some areas this has to be accepted and we are flexible to understand this can be part of project life and the WC manager has to make someunpopular decisions along the way. We are all experienced and adult to accept and understand this, but we feel some decisions are made which can potentially affect what we have beenworking to produce-a quality, first time installed, fully tested and functioning completion on all

project wells . If our recommendations are not being considered as worthy of implementing, and only lowest cost ‘fit for purpose solutions’ are required, we feel these decisions may reflect back on our team down the track and the quality well engineering work we have produced for the project to date will be forgotten quickly [emphasis added].” 316

Mr. Duncan (PTTEP Well Construction Manager) denied cost savings was the root cause of the wellcontrol deficiencies in GI, H1 and H2. 317 Yet, PTTEP’s denials lacked support in Inquiry testimony anddocuments.

Oil and gas consultants and vendors are placed in a very difficult situation of needing to take directionfrom their client (the oil and gas company), and agreeing somewhat to their demands, to retain existingand future business opportunities and avoid being “black-balled,” while still being partially responsible

for the decisions that are made. Therefore, oil and gas consultants and vendors need a confidential outletor government provided avenue to report gross permit deviations, safety violations and potentiallyhazardous situations.

314 Commission of Inquiry Document, AWT.0001.0001.0019315 Commission of Inquiry Document, AWT.0001.0001.0019316 Commission of Inquiry Document, AWT.0001.0001.0016317 Commission of Inquiry Transcript, March 30, 2010, p. 1346




This paper is focused on evaluating technical deficiencies and making technical recommendations; and asthe author is not an attorney, this paper does not include a formal review of Australia’s confidentialreporting mechanisms (whistle-blower reporting rules). However, it is recommended that Australia re-examine this system, and consult with AWT, in particular, as well as Atlas Drilling, on what additionalmechanisms and protections could be put in place for personnel and companies to come forward withserious concerns, without fear of reprisal or loss of future business opportunities.

Oil and gas consultants and vendors need a confidential outlet or government provided avenue toreport gross permit deviations, safety violations and potentially hazardous situations.

4.32 Minimum Health, Safety & Environmental Regulatory Standards

The elimination of Australia’s prescriptive standards was a root cause of this incident. If Australia’s 1967 prescriptive standards for well control barriers were still in place, the exchangeof a 9-5/8” PCCC for a 45m (148’) long, shallow-set cement plug barrier would not have beenapproved, likely adverting this disaster.

Even Mr. Jacobs (PTTEP CEO Australasia), when questioned by the Commission on this point, testifiedthat it would be preferable to have Australia establish minimum prescriptive standards:

“Q. How much variation is there, in your experience, in terms of expectations of DAs? A. I don't have a lot of dealings with other DAs. Our properties at the moment are mainly in the Ashmore Cartier region, for which the DA is the NT. We have a little inWA, but they're more exploration areas. I don't tend to get too involved in them.

My understanding, in talking to colleagues in the industry, is that there's - I don't think it's a widevariance. There's a couple of areas, I believe, where there are geographic differences as to howvarious States approach a particular subject, but the majority, again, will come down toindividuals within those authorities and how they perceive things could be done, and that

doesn't get resolved by combining, because you still deal with individuals. That gets resolved by having a common standard that has to be met, whoever is reviewing it at theend of the day . … there are differences. I don't think they are hugely varied, but just beingdifferences themselves obviously makes life interesting for companies that are operating inmultiple jurisdictions.” 318

In 2004 Australia revised its oil and gas regulations [ Australian Petroleum (Submerged Lands)(Management of Well Operations) Regulations 2004 ] to remove the requirement to meet Australia’slongstanding list of prescriptive technical standards found at The Schedule of Specific Requirements as toOffshore Petroleum Exploration and Production.

Yet, as explained above, many of the DAs were still relying heavily on the revoked Schedule of Specific Requirements due to the absence of any other written technical guidance to define “good oilfieldpractice.”

In 2006, Australia’s laws pertaining to offshore oil and gas development were amended to addressgreenhouse gas issues. The Australian Petroleum (Submerged Lands) (Management of Well Operations)

Regulations 2004 are required by The Offshore Petroleum and Greenhouse Gas Storage Act 2006. TheDA administers the requirements contained in the 2004 and 2006 acts.

318 Commission of Inquiry Transcript, April 7, 2010, p. 1683




As a reportedly more “modern” alternative to a prescriptive list of standards, in 2004 Australiaimplemented the “good oilfield practice” showing standard, allowing industry substantially moreflexibility in preparing applications. This essentially transitioned the regulatory regime into oneof “self regulation.” Current Australian regulations place the onus on the Operator and contractorsto minimize risk and prevent accidents.

The Commission explained that:

“Under this regime, in the event that the obligation to operate responsibly isn’t satisfied, theindustry faces the risk that government will respond with a more prescriptive regime.” 319

“The regime that we have had in place since 2004 affords operators the latitude to manageexploration and production activities in accordance with current technical and commercial

practice.” 320

Mr. Jacobs (PTTEP CEO Australasia) was questioned by the Commissioner about Australia’s current

system of industry self-regulation:

“Q. As we understand it, one of the cornerstones of the current system of regulation in Australia or across Australia is the concept of self-regulation, that is, reposing a high measure of trust and responsibility on the part of the licensees and, indeed, rig operators to manage their affairs in a way which is compliant with good standards of practice within the industry . A. Yes, that's correct, and it's not limited to titleholders and rig operators. Construction bargeoperators - anybody that has a facility under the definition of the Act. In terms of the health and safety on the well side, it's obviously the management of well regulations that are applicable at this time, so yes.Q. As I understand it, the system I just described which applies in respect of Australia's

offshore petroleum industry can be contrasted with, say, what applies in relation to American

petroleum industry participants, where there's a very, very high measure of prescription that applies . Is that your general understanding as well? A. That's my understanding. The Australian version, for want of a better description, is also adopted in a large part of Europe, the UK, Norway , et cetera, and it has been adopted in Australia as a result of that, yes. 321

The Commissioner countered that offshore oil and gas regulations in comparable countries (e.g. USA,Canada, UK, Norway) rely to some degree on prescriptive measures. Furthermore, none of thosecomparable countries relied merely on “self-regulation.”

“THE COMMISSIONER: Q. Mr Jacob, I also have had a very close look at the UK and the Norway system, and they don't have quite the same degree of prescription as the American

system, but they still have prescription when it comes to matters of well control and theintegrity . A. I have come to understand that, yes.Q. Whereas we do not have prescription of those matters.

A. No. I have come to understand that recently since preparing the submissions, et cetera. That'sone of the areas that I mentioned of guidance from regulators. How it's dealt with, whether it's

319 Commission of Inquiry Transcript, April 9, 2010, p. 1788320 Commission of Inquiry Transcript, April 9, 2010, p. 1787321 Commission of Inquiry Transcript, April 7, 2010, p. 1685




prescription or guidelines - I leave that to other people to decide how that's determined.Certainly, I think there's value .Q. At least my impression from the reviews that I have done, amongst the major oil-producing

countries, the comparable ones - we're at a different end of the spectrum than they are. I'm not making a judgment about that. It's just the fact...” 322

In 2004, the regulatory pendulum swung too far away from prescription, into a regulatory regimeof almost exclusive self-regulation. This system of self-regulation is unique to Australia.

The 2004 Australian Petroleum (Submerged Lands) (Management of Well Operations) Regulations set agoal of promoting new technology and new best practices, while merely requiring the Operator todemonstrate that its application met “good oilfield practice.”

The term “good oilfield practice” was not adequately defined in regulation, leaving its applicationsubject to unlimited government and industry interpretation. This has opened the door forpotential misapplication.

DA Staff testified that term “good oilfield practice” is hard to define, and that for technical guidance theyoften revert back to the revoked, but longstanding list of prescriptive technical standards found at TheSchedule of Specific Requirements as to Offshore Petroleum Exploration and Production. Mr. Marozzi(DA, Senior Engineer) testified:

“Q. What is your understanding of "good oilfield practice"? A. Undertaking work that has been planned in accordance with accepted industry practices .Q. And by "accepted industry practices", what do you mean? Can you provide some further information?

A. Well, it's sort of a hard one to answer , because it's such a broad level, but generally what theindustry does accept as a practical, safe method of undertaking the operation.Q. So is it the case that the primary thing you have in mind when assessing whether somethingmeets good oilfield practice is whether it's something that is commonly done in the industry?

A. I wouldn't say "commonly done", but just generally accepted as safe and effective.Q. You've said "generally what the industry does accept"; is that different from what's

commonly done in the industry ? A. Well, perhaps, but it doesn't mean it's commonly done; but perhaps, yes [emphasisadded].” 323

To compound matters, after the regulatory regime was changed in 2004, enacting the “good oilfieldpractice” standards and revoking the prescriptive standards, DRET and the DAs did not update theirwebsites to clearly articulate this change. The Commissioner harshly disciplined the DA (Mr. Whitfield)over this matter:

“THE COMMISSIONER: Q. I might also say, Mr. Whitfield more by way of an observation and not a matter that bears on you - that after this Inquiry was called, I visited the DRET website to

try to understand what the regulatory requirements were back in November of last year . Myrecollection is that that website indicated that the specific requirements, as they applied in 2005,were still applicable; in other words, it had not been updated for the subsequent revocations.

322 Commission of Inquiry Transcript, April 7, 2010, p. 1685323 Commission of Inquiry Transcript, April 13, 2010, p. 1979




On that basis, by accessing DRET's website, operators or people overseas who were trying to get a handle on the Australian situation would have been done a grave disservice . A. I wasn't aware that the specific requirements on RET's website were out of date until approximately two weeks ago when counsel asked our counsel for further information. It surprised me that it was out of date [emphasis added].” 324 “THE COMMISSIONER: I'm just making the observation at this stage that I think DRET and

the DAs need to get on their bikes and fix up what is manifestly unsatisfactory [emphasisadded].” 325

The Commissioner asked Mr. Marozzi (DA, Senior Engineer) about whether there was anything in theThe Schedule of Specific Requirements as to Offshore Petroleum Expl oration and Production that did notreflect good oilfield practice:

“Q. What I'm asking you about is not what the specific requirements don't include but what theydo include, and my question was, is there anything in the specific requirements that you have

come across that, in your view, doesn't represent good oilfield practice? A. No, no .[emphasis added].” 326

PTTEP and Atlas define “good oilfield practice” as:

“All those things that are generally accepted as good and safe in the carrying on of exploration for petroleum, or in operations for the recovery of petroleum, as the case may be.” 327

This definition is subject to broad interpretation, and is not suitable for determining regulatorycompliance or ensuring health, safety and environmental (HSE) objectives are met.

The regulatory term “good oilfield practice” needs to be more explicitly defined. The reviseddefinition should include health, safety and environmental (HSE) objectives, and establish firmand unambiguous compliance yardsticks.

The Commissioner questioned PTTEP Well Construction Manager (Mr. Duncan) about the currentAustralia regulatory standard of “good oilfield practice.”

Q. And if the operator goes down toward the bottom of the document, again, in the third-last paragraph from the bottom of the screen there is a reference in the first line to “good oilfield practice” . Do you see that? A. I do.Q. What did you understand that phrase to mean?

A. It's not one of my favourite phrases . I understand it to mean that it’s in accordance withwhat’s commonly undertaken and appropriate.Q. Why is it not one of your favourite phrases?

A. Because it’s not very specific. Q. Do I take it that your preference would be for a greater level of stipulation or prescription toapply within the regulatory framework?

A. No. That's reading a lot into that paragraph.

324 Commission of Inquiry Transcript, April 15, 2010, p. 2220325 Commission of Inquiry Transcript, April 13, 2010, p. 2221326 Commission of Inquiry Transcript, April 13, 2010, p. 1980327 Commission of Inquiry Document, PTT.9000.0009.0212




Q. No, I'm just asking about your own resistance to this concept of good oilfield practice, and I'masking whether that resistance is based on a preference you would have for licensed operators tobe subject to a greater level of prescription so that they didn't have to work out for themselveswhat good oilfield practice required?

A. I don't have a firm view as to what level of prescription there should be, but my unhappinesswith the term “good oilfield practice” is more related to the many interpretations that different

people with different levels of understanding will apply. For example, when I first started in theindustry, the term was not “good oilfield practice,” but “that’s not API,” and that term related tothe American Petroleum Institute, which had recommendations on procedures and how thingswere done. Everybody used the term. Very few people knew what it meant, including me at thetime.Q. The term is actually defined in the well construction standards o n page 5 of the document, if the operator could go to that and if the operator could scroll down. You will see there a definitionof “good oilfield practice.”

A. Yes.Q. Do I understand you to be saying that, as a matter of practical reality, it can be hard toidentify the particular things that are generally accepted as good and safe?

A. No, things can generally be determined, what are good and safe, but it’s not something that’s easy to measure. 328

The problems associated with a lack of minimum prescriptive standards are even echoed byPTTEP’s Well Construction Manager, as his own three decades of experience show that “goodoilfield practice” is ambiguous, widely interpreted and is in large part a function of a person’sexpertise and experience.

The fact that Mr. Duncan, with more than three decades of experience, struggles to define the term “goodoilfield practice” and explain what that actually means in terms of “nuts-and-bolts” to the Commission isa clear indication that a regulatory system based on an undefined principle is a flawed approach.

Regulatory systems must have plainly articulated minimum prescriptive standards that are easilyunderstood and implemented by personnel with all levels of experience and expertise. The rules must beclear, simple, measurable and verifiable. Absent these criteria, industry may opt to take shortcuts andregulators do not have clear standards to use in processing permits and measuring compliance.

When regulatory standards do not exist or are vague the door is open to shortcuts and cost-cuttingmeasures that can increase risk. The rules must be clear, simple, measurable and verifiable.

There needs to be consistency in standards, interpretation and implementation across all offshoreregulators. Achieving this starts with establishing simple, straightforward minimum standards for thegovernment to implement and for industry to follow.

In theory, the 2004 regulatory scheme can work, but its success is dependent on an applicant that isexperienced, trained, and qualified to select and implement the best available technology and practices(i.e. “good oil field practice”). It’s also dependant on the agency approving the application being staffedwith personnel who are experienced, trained, and qualified to determine if “good oil field practice” has, infact, been selected, and who are also capable of making any needed recommendations for alternatesolutions and practices.

328 Commission of Inquiry Transcript, April 7, 2010, p. 1525




In the event that the applicant is not experienced, trained, and qualified to make that initial assessment, orfor reasons of cost control, time savings, or other business advantage, the applicant does not propose goodoilfield practice, it is then incumbent on the approving agency to make some very difficult decisions onthe permit application.

At a minimum, the approving agency must engage in a technical debate with the applicant about whattruly is good oilfield practice. It can be challenging for agency staff to engage in a technical debate whenfaced with late, rushed applications and highly paid oil and gas staff and consultants contending theirapplication is worthy of approval.

Nonetheless, agency staff must be able to make the difficult decision of denying an application, orapproving it subject to “good oil field practice” stipulations. Agency staff must have the expertise andqualifications to defend their position and provide high quality advice to industry.

The difficulty of making unpopular permit denial decisions, or permit decisions that cause rig delays orincrease costs, is compounded when the same agency making the permit decisions is also responsible forensuring ample oil and gas revenues are generated to fund public needs.

In Australia, the approving agency (the Designated Authority (DA)) is also the resource developmentagency. The DA has the unenviable position of promoting oil and gas development while alsoconstraining its implementation by permit approvals and denials. This dual mission creates the stage forpotential conflicts of interest.

Government witness testimony from Northern Territory DA Staff 329 clearly showed that:

There was insufficient government staff to review, approve, and oversee Timor Sea offshoredrilling operations;

Government staff and management lacked the experience and qualifications needed to makecomplex technical decisions required when reviewing waivers for well control barriers;

There was a culture of cozy relationships between the approving agency and industry;

There was a history of “rubber-stamping” industry proposals with little or no independenttechnical analysis;

Government technical staff believed it was their job to issue permit decisions on the “fly” andavoid holding up rig operations, regardless of the risk or complexity of the permit decision;

Government staff had no formal written standard operating procedures for conductingtechnical reviews or making risk-based decisions;

Government staff equated permit processing speed with successful job performance, ratherthan basing successful job performance on the quality of the permit technical review andassessment conducted at a reasonable, professional pace; and

Government staff generally accepted most industry requests and proposals without adequatetechnical review.

329 Commission of Inquiry Transcripts, April 12-15, 2010




Historically, international governments have fluxed between the use of “prescriptive” standards, “goalorientated” standards and “principle based” standards. The nomenclature varies by international location,but the general question remains the same. How much specific direction must the government giveindustry to ensure that oil and gas development is conducted safely and responsibly without stiflingtechnical innovation?

History has shown that if government is too prescriptive, regulations do not keep pace withadvancing technological improvements, frustrating industry innovation. Alternatively, history hasalso shown that the lack of clear, minimum government standards (“bottom-line” or “floor”standards) can result in shortcuts and cost-cutting practices that, in some cases, have catastrophicresults. If government does not establish the basic “speed limit,” offshore development has thepotential to speed out of control.

To use an auto analogy, on major highways government safety objectives are met by setting a speed limit,but not limiting the color or weight of vehicles. However on secondary roads, government may need toestablish additional minimum standards to protect the asphalt base, by limiting both speed and vehicle

weight. The level of minimum prescriptive standards should be directly correlated to achieving thedesired public goals and objectives.

A policy balance between prescriptive standards and technical innovation and flexibility must beachieved. As governments develop regulations that aim to strike that balance, a stead-fast eyemust be kept on the ultimate goal of human health, safety and environmental (HSE) protection.

For example, a BOP should always be in place when drilling and completing a well. Requiring the use of BOPs is a logical minimum prescriptive standard that not only is consistent with good oil field practice,but will also maintain relevancy for decades to come.

In the oil and gas industry there is a set of prescriptive minimum standards that are sofundamental to meeting human health, safety, and environmental (HSE) protection that they havebeen used in regulation and practice for decades. This set of minimum prescriptive standardsshould be codified in laws and regulations.

Similarly, lessons learned from other well blowouts have resulted in many international governmentscreating regulations that require two, independent, pressure-tested barriers be set in a wellbore before aBOP is removed. The two-barrier well control rule is a minimum prescriptive standard that is necessary toensure human health, safety and environmental (HSE) protection. There is no foreseeable reason to takethe risk of a single well barrier system; therefore a two barrier requirement should be included inregulation as a minimum prescriptive standard.

Additionally, minimum prescriptive standards for cement integrity should be set. Both the 2009 Montarawell blowout and the 2010 USA Gulf of Mexico Macondo well blowout resulted, at least in part, fromcement integrity failures, inadequate QA/QC procedures and poor decisions related to cementing.

Whether they are called minimum prescriptive standards or termed principle based regulations, a basic setof minimum standards is necessary to protect health, safety and the environment (HSE) and givegovernment regulators a baseline for determining compliance.




Whether they are called minimum prescriptive standards or termed principle based regulations, abasic set of minimum standards is necessary to protect health, safety and the environment (HSE)and give government regulators a baseline for determining compliance.

To return to the auto analogy, minimum prescriptive standards for automobile manufacturers include the

requirement to have brakes, a steering mechanism and safety harnesses. However, companies have theoption to build a wide range of automobile models and select from a wide range of vendors for the partsthat are included in those automobile models, and customers have the discretion to buy the type and brandof automobile that best meets their transportation goals and objectives. In this way, standards that areimportant to protect human health, safety and the environment (HSE) are mandated, while somediscretion is retained by manufacturer.

In setting minimum prescriptive standards, government may further bind the standard with some principlebased objectives. To take the automobile analogy one step further, government may require that brakesare designed and built with sufficient strength to arrest automobiles when traveling at freeway speeds.Similarly, safety harness standards may establish requirements that provide for the safety of smallchildren and prevent serious injury. Nonetheless, broad flexibility for technical innovation to meet these

principle based objectives remains.

The 2004 regulatory reform for Australian oil and gas exploration and development did notachieve a balance between prescriptive standards and latitude for innovation. It eliminated alllevels of prescription, defaulting to an undefined standard of “good oilfield practice.” This leftgovernment officials with an ambiguous standard, making it difficult to process permits andmeasure compliance.

The Commissioner noted that he was studying international regulatory models. However, theCommission of Inquiry process did not have any witnesses testify on international best practices. Thiswould be a good next step for the Commission to take, building on the work already successfullyachieved by the Commission.

While USA government officials were very critical of Australia’s standards 330 when the 2009 H1 Montarablowout occurred, the 2010 Gulf of Mexico blowout is clear indication that USA’s minimum prescriptivestandards for cementing and blowout preventers are also in need of review.

Walter Cruickshank, USA deputy director of the Minerals Management Service, stated:

“There are some differences between here and there that are significant. The well design is not one that we would have approved. They had a single barrier to control the well. We require redundant barriers. We also require that the barriers be tested at pressures at least as great as those expected to be found in the reservoir. It’s our understanding there was no such requirement to test the barrier offshore Australia. We also have what we believe is the most aggressive oil spill contingency planning and oil spill drill program in the world where we areconstantly making sure people are able to respond quickly [emphasis added]. 331

Hindsight will be 20-20 for the USA, but even with multiple barriers, the worst blowout in USA historyhas occurred. Early indication is that the Gulf of Mexico blowout (Macondo well) also suffered fromcement integrity issues, and blowout preventer system shear rams that may not have been designed to cut

330 Commission of Inquiry Document, PTT.9003.0074.0125331 Commission of Inquiry Document, PTT.9003.0074.0125




the higher strength piping used. Additionally, early reports are that the BOP may not have beenadequately tested, nor inspected/audited. Therefore, a more detailed set of prescriptive regulations is onlyeffective if it is coupled with an inspection, audit and enforcement system that ensures compliance.

A more collaborative approach between experts in Australia, USA and other oil and gas producingcountries should be developed. Experts should work together to examine lessons learned from theblowouts in both Australia and the USA, and develop recommendations for international best practicesand regulations to mitigate future blowouts.

A team of Australian and international industry experts could be gathered to identify a list of critical minimum prescriptive standards that should be codified in regulation to meet health,safety and environmental (HSE) objectives.

While the best efforts should be made to codify minimum standards that will stand the test of time,inevitably there will be some future technical innovations that will require revisions to regulatorystandards. Therefore, two corollary mechanisms should be instituted to: (1) update regulations on aroutine basis and (2) establish a formal technical expert review process to examine any proposed waivers

to the existing standards. Approval of proposed waivers should be based on an applicant’s ability todemonstrate that it has developed a technology that meets or exceeds the minimum prescriptive standards,and that it is in Australia’s best interest to approve this technical innovation ahead of a regulatoryamendment.

A system can be established to update regulations on a routine basis to take into account technicalinnovations. A formal technical expert review process can be established to examine anyproposed waivers to the existing standards. Approval of proposed waivers should be based on anapplicant’s ability to demonstrate that it has developed a technology that meets or exceeds theminimum prescriptive standards, and that it is in Australia’s best interest to approve this technicalinnovation ahead of a regulatory amendment.

All international regulatory authorities face the challenge of keeping their regulations current with newtechnology. Ideally, routine regulatory revisions can be used to keep regulations current with newtechnology. However, agencies that do not have funding or staff to do frequent regulatory revisions caneasily establish minimum engineering and safety standards to set a “floor” on what is expected of theOperator, and then add a clause stating that new technology may be approved by the agency if it is provento provide “equal or greater protection” of human health, safety, and the environment (HSE). This allowsthe agency the flexibility to approve new technology without compromising basic minimum standards.Additionally, this does not prevent agency personnel from adding a more stringent requirement in theapproval decision, if they become aware of new “good oil field practices” prior to formal adoption of regulatory amendments.

In the March 3, 2010 WWF report submitted to Commission, examples of international oil and gas

regulations are cited from Norway, Canada, and the USA. These examples show regulatory systems thatcouple a basic prescriptive list of standards with the opportunity for the Operator to improve on thosestandards by applying to use a technology or practice that exceeds the minimum prescriptive standards. Inthis way, there is at least a minimum standard that must be met, with no debate.




If the minimum prescriptive standards of the Specific Requirements as to Offshore Petroleum Exploration and Production were left in place, or used in a careful fashion to thoroughly examinethe proposed H1 WOMP and subsequent drilling applications, it is very likely that the H1incident could have been averted.

The prescriptive standards ( Specific Requirements as to Offshore Petroleum Exploration and Production) clearly require cement plugs to be placed in the well when it’s temporarily abandoned;they also clearly require surface wellhead control on wells drilled into hydrocarbon bearing zones.

Minimum technical standards are critical. Flexibility can be afforded by allowing for newtechnology and practices that provide “equal or greater protection” of human health, safety, andthe environment (HSE).

Minimum regulatory standards also ensure that responsible Operators are not placed at a competitivedisadvantage to those Operators taking shortcuts.

4.33 Pre-Drill Risk and Impact Assessment

While blowouts are infrequent, they do occur, and when then do, they are catastrophic.

A root cause of this incident was complacency, because Australia’s last major offshore blowoutwas in 1984.

Offshore oil and gas drilling and production is a high risk, high consequence business. Therefore,vigilance is not just warranted, it is a fundamental operating principle.

The pre-drill environmental assessment, prepared by URS Australia Pty Ltd., Section 6.4.2.4, assumedthat a well control problem was highly unlikely:

“ With current technology, the risk of a well blowout is considered low . There are elaboratemonitoring systems to detect potential blowouts and such events can occur only if all themonitoring systems fail and if the casing, wellhead or blow-out preventers (BOPs) failcatastrophically.”

“In almost 30 years of operation, the oil and gas industry in Australia has drilled over 1500exploration and development wells and produced over 3,500 million barrels of oil. … There havebeen no blow-outs in Australia since 1984, which is evidence of the technological and proceduralimprovements that have occurred over the last two decades.” 332

Technological and procedural improvements cannot eliminate human error and mechanical malfunctions.

332 URS Australia Pty Ltd., Section 6.4.2.4




Blowouts are reasonably foreseeable consequences of offshore drilling and completionoperations. Pre-drill environmental assessments should include a risk and impact assessment of the worst-case blowout scenario. Human error and mechanical failure scenarios should beincluded in this assessment.

4.34 Contractor Responsibility

The drilling contractor has a responsibility to provide technical advice to its client to ensure that the wellis drilled safely and personnel are kept out of harms way. When problems arise, the onus is on the drillingcontractor to bring its concerns to the attention of its client.

If the Operator is unwilling to address or resolve health, safety or environmental (HSE) concerns,the drilling contractor should be required to report the problem to the appropriate agencies forimmediate resolution. Legal protections should be in place for individual employees, as well ascompanies, to freely report safety concerns. These legal protections should be designed to prevent

repercussions to those reporting safety violations.

Atlas Drilling points the finger at PTTEP, stating that the blowout occurred because PTTEP did notfollow its own Well Construction Standards that require a long-term suspended well to have two testedbarriers installed in the annulus and wellbore above hydrocarbon and pressured zones.

Yet, Atlas Drilling did not follow its own drilling standards, which required a BOP to be placed on wellH1 as part of the re-entry procedure, because the well did not have two well control barriers installed.

Atlas Drilling drilled and suspended H1 and was fully aware of challenging reservoir conditionsencountered along the way (e.g. lost circulation zone, hydrocarbons, and casing shoe integrity issues).Moreover, Atlas Drilling was physically responsible for suspending H1 and was in possession of a March12, 2009 change order clearly stating that additional cement plugs were not placed in well H1. AtlasDrilling’s submission shows it knew the 13-3/8” PCCC was missing and the 9-5/8” cement job wascompromised.

When Atlas Drilling removed the 9-5/8” PCCC it was aware of the lack of controls in place on H1.

Atlas Drilling should not have agreed to remove the PCCC without a BOP in place.

PCCC removal was contrary to Atlas Drilling’s own Standard Operating Procedures and well controlcertifications held by its drilling foremen.

Atlas Drilling should not have agreed to leave H1 uncapped and move the rig over to work on theGI and H4 well tie-ins, especially since gas bubbling was observed.

Atlas Drilling’s HSE Policy is to:




“... take the time needed to plan and carry out the work in a safe manner…reactingimmediately to unsatisfactory conditions [emphasis added].” 333


“The OIM is responsible for ensuring that the installation's well control equipment is supplied "fit for purpose" and maintained in this condition … The Operator's Representative has aresponsibility to the OIM to provide specialist advice on well control [emphasis added].” 334

Thus the OIM should have set a BOP. The Atlas Well Control Manual states:

“It is the OIM's responsibility, with the Rig Superi ntendent/Toolpusher’s assistance, to review theterms of the drilling contract and each well plan, to ensure that they, the installation and the creware capable of safely and efficiently providing the required service. Any concerns arising from

this review which cannot be resolved with the onboard Operator's Representative must beimmediately communicated to the Operations Manager for discussion with the Operator's

Drilling Superintendent [emphasis added].” 335


“ The OIM has the final responsibility for well control. A Company OIM will be trained in wellcontrol, but as he is not necessarily a drilling professional, he will consult with the RigSuperintendent/Toolpusher, Operator's Representative and Rig Superintendent, to arrive at decisions on well control once a well control problem has occurred [emphasis added].” 336

PTTEP’s Forward Plan included instructions for removing the 9-5/8” PCCC and leaving the well open toatmosphere. This plan was uncontested by Atlas Drilling at the time. 337 PTTEP’s Forward Plan stated:

“ Any doubts on the operation or improvements please let us know . The key to this operation onthe platform is to get it right the first time [emphasis added].” 338

Atlas Drilling stated that the OIM is responsible for the safety, health and welfare of all persons on theinstallation.

“The OIM ensures that the client drilling objectives are met, giving due regard to achieving thisin a safe and effective manner . Whenever he thinks it is necessary for the safety of the personnelon board or integrity of the rig , he has the ultimate power to stop operations being carried out

and he has the right to make those decisions ... [emphasis added].” 339

Atlas Drilling OIM’s statement (Mr. Trueman) said the OIM agreed to remove the 9-5/8” PCCC,because he assumed the “casing was fully cemented.” 340 No steps were taken by the OIM to examinethe cement integrity or consider the two barrier good oilfield practice requirement in making this

decision.

333 Commission of Inquiry Document, PTT.9000.0009.0243334 Commission of Inquiry Document, SEA.009.001.0751 and SEA.009.001.0752335 Commission of Inquiry Document, SEA.009.001.0751 and SEA.009.001.0765336 Commission of Inquiry Document, SEA.009.001.0751 and SEA.009.001.0789337 Commission of Inquiry Document, WIT.1501.0001.0349338 Commission of Inquiry Document, WIT.1501.0001.0349339 Commission of Inquiry Document, WIT.1501.0004.0184340 Commission of Inquiry Transcript, March 16, 2010, p. 88




The drilling contractor has a responsibility to provide technical advice to its client to ensure thatthe well is drilled safely and personnel are kept out of harms way.

Equally, the cement contractor has a responsibility to provide technical advice to ensure the well isproperly cemented and integrity tested, and cementing provides an adequate well control barrier. This

philosophy and responsibility is reiterated in the Atlas Well Control Manual:

“Third Party employees, such as the Mud Engineer and Mud Loggers, will be called on by theOperator's Representative, the Rig Superintendent/Toolpusher and the OIM to assist in wellcontrol decision making, according to their area of expertise. They have a responsibility to bring

any concerns they may have about planned operations, equipment to be used or procedures tobe followed to the attention of the Operator's Representative, the Rig Superintendent/Toolpusher or the OIM [emphasis added].” 341

Atlas Drilling Manager (Mr. Gouldin) testified PTTEP personnel onsite should have experience to knowwhen remedial cement work is needed. 342

The cementing contractor (Halliburton) understood the problems with the failed float, wet shoe,and inadequate cement job, but did not raise any well safety concerns.

The Commissioner questioned PTTEP Well Construction Manager (Mr. Duncan) about PTTEP’sexpectations for contractor performance, especially in regard to altering PTTEP on serious issues:

“Q. It sounds as though you're saying that in relation to the operation of cementing the casingshoe, PTT wasn't really purchasing advisory and consulting services from Halliburton; it wasreally purchasing the know-how as to what to do in order to follow instructions. Is that right?

A. No, I wouldn't put it that way. I'd say we were taking advisory information, but we can't step away from the responsibility simply by asking someone else for advice. Q. I'm just wondering, do you say that the nature of your arrangements in place with Halliburtonat the time required the Halliburton cementer to independently evaluate the merit of that instruction and provide advice as to it, or do you say that his job, in effect, was to do what he wastold to?

A. Can I say both?Q. Well, you can. I might not understand it.

A. Okay. His job was to do what he was told, but his job was also to wave a red flag if he thought something was incorrect [emphasis added].” 343

Because the use of contract resources is so prevalent in offshore oil and gas industry operations,regulations must not only apply to the oil and gas Operator – there also needs to be standards of performance, safety, training and reporting obligations for the contractors.

The current system requires contractors to be beholden to the Operator. This creates gaps,inconsistencies and a general lack of direct responsibility to protect public resources.

341 Commission of Inquiry Document, SEA.009.001.0751 and SEA.009.001.0789342 Commission of Inquiry Transcript, March 16, 2010, p. 57343 Commission of Inquiry Transcript, April 7, 2010, p. 1519




Contractors that follow Operator orders, work quickly, and keep costs low get return business.Contractors that challenge the good oilfield practice selected by the Operator often do not see repeatbusiness.

Regulatory requirements need to be established for contractors to ensure that they are required tostop unsafe acts, and immediately report and remedy unsafe operations. There should beincentives and protections in place for contractors that report, and there should be penalties forthose that don’t.

This paper does not address the legal reporting requirements of a drilling contractor if it observes a safetyissue, nor does it address the legal protection afforded a whistle blower in Australia, but these issuesshould be addressed by the Commission. Does the business climate in Australia allow for, or evenencourage, contractors to point out concerns or make safety recommendations to the Operator? Can thedrilling contractor refuse to take unsafe steps, even if directed by the Operator? Are these safe-practiceand open-reporting behaviors encouraged or penalized?

Contractor’s legal requirements, rights and responsibilities to report safety and permit violations

warrant examination.

Prior to Australia’s 2004 regulatory revision that removed prescriptive standards, Section 513(2) of TheSchedule of Specific Requirements as to Offshore Petroleum Exploration and Production required:

“...(W)hile drilling operations are being undertaken on a platform, a well shall not be left in a condition which in the opinion of the person in command of the platform or the Director, isunsafe . Prior to the cessation of drilling operations, even temporarily , the well shall be made

safe in accordance with good oilfield practice [emphasis added].”

Additionally, Section 513(3) required all wells to be secured at the surface.

Minimum prescriptive standards, previously found in The Schedule of Specific Requirements asto Offshore Petroleum Exploration and Production at Section 513, should be re-established toensure that wells are never again left in an “unsafe condition” by the person in command of theplatform.

4.35 Inspections and Audits

Routine onsite inspections and audits are a critical component of a high quality regulatoryprogram. Crafting stringent regulations is only one step in the process. Routine inspections andaudits are needed to ensure that regulations and permit stipulations are followed, and to identifytechnical, safety, and environmental issues.

An initial inspection should have been performed after the Montara Wellhead Platform was installed inJuly 2008.

Audits of drilling logs, casing and cementing records, pressure data, and other well completion recordsshould have been completed between January 2009 and August 2009.




An onsite visit and/or records review (at a minimum) should have been completed in April 2009 toexamine the condition of the suspended wells before the rig left the platform, because once the rig left theplatform, remedial or well control work could not have been done without returning the rig.

The drilling rig should have been inspected again prior to commencing well tie-in activities on theMontara Wellhead Platform, including testing and agency verification of the blowout preventer system,and a review of well drilling and completion plans and procedures.

On August 21, 2009 the Montara H1 well blowout commenced. 344 More than one year hadpassed since the Montara Wellhead Platform was installed in July 2008, and not even one onsiteinspection had taken place by the DA, NOPSA or DEWHA.

The DA stated that Daily Drilling Reports are submitted by PTTEP to the DA and that:

“ These reports allow the Territory to monitor the operations, at least at the level of detail required to be provided in the reports . The assessment of Daily Drilling Reports against approved work programs (drilling programs and WOMPs) allows the Territory to determine

progress, performance and compliance.

Up to the point of the incident on 21 August 2009, the Territory has assessed all drilling programs and WOMPS as meeting the requirements of the legislations, guidelines and good oil field practice [emphasis added].” 345

Yet, DA testimony conflicted with the DA’s written submission to the Commission. The DA’s writtensubmission painted a rosy picture of government oversight; whereas, DA Staff testified that they lackedsufficient technical personnel, funding resources, and technical background to provide oversight. 346 PTTEP Management confirmed there was no audit of a well or rig issued between April 2009 and August2009.347 The DA testified it did not have the personnel or funding to conduct offshore inspections toverify compliance.

The DA’s written submission painted a rosy picture of government oversight; whereas, DA Staff testified they lacked sufficient technical personnel, funding resources, and technical backgroundto provide oversight, and that they did not have the personnel or funding to conduct offshoreinspections to verify compliance.

NOPSA argued that it was appropriate for almost a year to pass, from installation of the Montara PlatformJacket (September 2008) to the H1 well blowout (August 2009), without a NOPSA platform inspection.NOPSA argued that an inspection was not needed because:

“The Montara facility is normally unattended , has no accommodation facilities and was not producing hydrocarbons prior to the uncontrolled hydrocarbon release. Therefore, NOPSA hasnot inspected the Montara facility prior to the uncontrolled hydrocarbon release [emphasisadded].” 348

344Atlas Drilling, Submission No. 1501.0001.0007345 DA, Submission No. 4000.0001.0028346 Commission of Inquiry Transcripts, April 12-15, 2010347 Commission of Inquiry Transcript, March 25, 2010, p. 969348 NOPSA, Submission No. 3003.0001.0013




This explanation is inconsistent with NOPSA’s responsibility for regulating the occupational health andsafety of people at or near offshore petroleum facilities, based on the fact that people were located at theplatform: in September 2008 for the Jacket installation (and potentially working on the platformthereafter); from January 2009 to April 2009 for drilling operations; and in August 2009 for TopsideModule installation and tie-in activities. Drilling operations are conducted 24 hours a day, and normallysleeping quarters are placed nearby. Therefore, people were at the Montara Platform working duringthe period of September 2008 to August 2009 . Additionally, the platform underwent a majorinstallation, warranting an onsite inspection. If NOPSA did not have the time to even complete itsexisting facility inspection duties, how can it argue it should take on additional oversight and inspectionduties?

Furthermore, to argue that an inspection was unnecessary because the platform was “not producinghydrocarbons” during September 2008 to August 2009 appears to dismiss all other potential safetyhazards that could have been identified by an inspector (e.g. electrical, fire, unsafe practices, faultyequipment, etc.).

A NOPSA inspection of the Montara Platform was warranted during its first year of activity.

The Petroleum (Submerged Lands) (Management of Safety on Offshore Facilities) Regulations 1996 (MOSOF Regulations) and the Petroleum (Submerged Lands) Act 1967at §150XE specify that NOPSA’srole is to:

“(c) to promote the occupational health and safety of persons engaged in offshore petroleumoperations;

(d) to develop and implement effective monitoring and enforcement strategies to securecompliance by persons with their occupational health and safety obligations under this Act and the regulations;

(e) investigate accidents, occurrences and circumstances that affect, or have the potential toaffect, the occupational health and safety of persons engaged in offshore petroleum

operations in Commonwealth waters;...(f) to advise persons, either on its own initiative or on request , on occupational health and safety matters relating to offshore petroleum operations;...[and]

(h) to cooperate with: (i) other Commonwealth agencies having functions relating to offshore petroleum operations; and (ii) State or Northern Territory agencies having functions relatingto offshore petroleum operations; and (iii) the Designated Authorities of the States and the

Northern Territory [emphasis added].”

Facilities covered by NOPSA’s work are defined by the Petroleum (Submerged Lands) Act 1967 as “… a structure or installation of any kind ” , which would include the Topside Module and all the wellheadcontrol systems. The safety of methods used to connect a well to the wellhead control system appears tobe within the purview of NOPSA. NOPSA doesn’t deny that wells are included in the definition of certainfacilities, but argues that in some cases, the facility Operator is not the “titleholder” and may have littleknowledge or control over the well. 349 Yet in this case, PTTEP is the titleholder and the facility Operatorfor both the Montara wells and platform. Therefore, that argument does not apply.

The safety of methods used to connect a well to the wellhead control system appears to be withinthe purview of NOPSA, because NOPSA is responsible for personnel safety (including platformand rig personnel).

349 NOPSA, Submission No. 3003.0001.0021




There was an overall systemic problem with quality assurance and quality control (QA/QC) on H1. Thewellbore as-built was not accurately maintained, perpetuating depth errors in a number of wellconstruction diagrams and documents. Cement calculations were not accurate, and cement placementdepths and integrity were not verified.

4.36 Emergency Pre-Planning and Relief Wells

Australia should consider adopting more stringent requirements for well control planning, including plansfor a relief well and plans to cap the well, as a possible alternative if it is safe to access the platform. Inthe case of the H1 well blowout, both PTTEP and NOPSA determined it was not safe to return to theplatform to conduct well capping. 350

Locating a suitable, technically capable rig, with qualified crew, and executing a contractualarrangement for an extremely dangerous, hazardous mission should be part of advanced offshorewell planning.

Control of the H1 Montara Well blowout required a separate relief well rig. It took 74 days (2.5 months)to initially kill the well, and 135 days (4.4 months) to completely secure the well to abandonment status.The blowout commenced on August 21, 2009. The relief well rig intersected the Montara H1 well onNovember 3, 2009. Cement was pumped on November 3, 2009 to control the well, but the well was notfinally abandoned until January 13, 2010, when two barriers were placed in the well. 351

Looking forward to well planning down the road, it is important to ensure that a more efficient and rapidresponse is achieved for future well incidents.

The Australian Petroleum Production & Exploration Association Limited (APPEA) submitted that:

“ Well blowouts do occur . APPEA understands that worldwide, over 500 offshore well blowouts have occurred in the past 50 years of offshore operations [emphasis added].” 352

APPEA cited the Norwegian SINTEF Offshore Well Blowout Database that includes 544 offshoreblowouts/well releases since 1955.

USA oil spill statistics also show that blowouts occur, and proper well control planning is necessary:

“From 1971 to 2005, 276 exploration and development blowouts occurred on the OCS whiledrilling from approximately 34,000 wells. Thirty-three of those 276 blowouts resulted in oil spillsof crude or condensate with the amount of oil spilled ranging from, 1 bbl to 350 bbl.” 353

This data shows a history of 1 blowout for every 123 wells. A blowout for every 123 wells drilled isclearly a “reasonably foreseeable” event. Furthermore, the USA is currently experiencing the worstblowout in its history at the Macondo well in the Gulf of Mexico.

350 PTTEP, Submittal No. 1000.0002.0005351 http://www.upstreamonline.com/live/article203344.ece352 APPEA, Submission to Commission of Inquiry, December 22, 2009.353 Shell Chukchi ODPCP, p.2-15




Canada has also determined that blowouts are “reasonably foreseeable” events. Canada’s Oil and GasDrilling Regulations 354 at Section 79 [Attachment C] require:

“79. (1) Every operator shall ensure that contingency plans have been formulated and thatequipment is available to cope with any foreseeable emergency situation during a drilling

program, including(a) a serious injury to or the death of any person;(b) a major fire;(c) the loss of or damage to support craft;(d) the loss or disablement of a drilling unit or a drilling rig;(e) the loss of well control;(f) arrangements for the drilling of a relief well should such become necessary;(g) hazards unique to the site of the drilling operation; and (h) spills of oil or other pollutants.” [emphasis added]

Canada’s Same-Season Relief Well (SSRW) Policy was established by Cabinet Order in 1976. 355

“Since floating offshore drilling operations commenced in the Beaufort Sea in 1976 it has been

the policy of the Government of Canada that an operator not drill into a potentially hydrocarbon-bearing zone, (the risk threshold) without the ability to drill a relief well in the same season in the event of a blowout.

This policy is meant to significantly reduce the damage to the environment that would result if an oil blowout continued to release oil through the winter season unchecked.

The present procedure is as follows. On September 25, for wells drilled in open water, the statusof operations is reviewed and any further operations conducted below risk threshold depth need aseparate and distinct approval. This approval depends on weather, the availability of a relief well platform , depth of the hole being drilled and other factors. The date, September 25, waschosen as it would allow a period of at least 60 days to mobilize a relief platform, to drill a relief

well and to kill the blowout prior to the formation of 30 cm thick ice.

As new drilling systems were introduced to the Beaufort Sea and better ice breaking capabilitywas developed the concept of same season relief well capability 356 was maintained but drillingbelow the risk threshold depth was occasionally allowed beyond September 25 based on theavailability of alternate relief well platforms and capable ice breaking equipment.

Three times over the past 15 years an operator has lost control of its well during drilling operations in the Beaufort Sea . None of these incidents resulted in an oil blowout or in a serious pollution incident and the operators moved swiftly to control their wells and to contain and remove any contaminants in the Beaufort Sea. These incidents underscore the need for vigilance

and the need for a workable same season relief well contingency plan [emphasis added].” 357

354 Canada Oil and Gas Drilling Regulations, current as of October 21, 2009.355 Dr. Bharat Dixit, Canada’s Chief Conservation Officer, Regulation of Oil & Gas Activities in the Canada’s Northern Frontier, The Arctic of Canada- Canada’s Evolving Offshore Oil and Gas Industries, Offshore Technology Conference 2007, May 2007, Houston, Texas, USA356 Same season relief well capability refers to the capability to drill a relief well and control a blowout in the same season in which the originalwell was being drilled. Same season relief well capability requires the ability to begin mobilization of an alternate relief well drilling system assoon as a blowout occurs, and once relief well operations are started, the ability to conduct those operations on a relatively continuous basis, to asuccessful conclusion.357 A Report to the Minister of Indian Affairs and Northern Development Regarding Issues Arising from the Environmental Impact Review BoardReviews of the Isserk and Kulluk Drilling Program Applications, Prepared by the Beaufort Sea Steering Committee, April 1991.




Therefore, Canada requires a relief well rig to be available nearby for immediate intervention. Immediateaccess to an alternate rig capable of drilling a relief well is critical.

PTTEP’s submittal summarized the steps it took to locate and negotiate a relief well rig.

Locating a suitable, technically capable rig, with qualified crew, and executing a contractual arrangementfor an extremely dangerous, hazardous mission is something that should be planned well in advance.

Similar to Canada, the State of Alaska in the USA requires extensive well control pre-planning. Alaskarequires drilling Operators to have a written well control plan that includes plans for a relief well, and aplan to cap the well within 15 days. 358

Responding to a catastrophic blowout is an extremely dangerous and hazardous mission. There areserious human health and liability consequences that other offshore petroleum industry members mustconsider before jumping in to help. Cautious assessment of the situation is warranted. Companies must becareful not put their employees in harms way without a well-thought-out plan and coordinated effort withthe Operator and agencies directing the response. They must consider if their staff are trained andqualified to respond to this type of incident, and whether their equipment is appropriate and reliable forthe response. Sending in well meaning, untrained, poorly equipped volunteers can compound a disaster.Whereas, enhancing response assets with well trained and well equipped personnel who have clearlyassigned roles in the incident management structure can prove beneficial. This requires coordination andpre-planning.

Thus, it is critical to negotiate Memorandums of Agreement and contracts for “mutual response aid” andemergency assistance with other Operators and contractors in advance of an incident. These contractualand liability issues are complex, and require companies to thoroughly vet human health, safety, andenvironment (HSE) procedures used by other companies before agreeing to join in on mutual aidcontracts. As noted above, both Canada and the USA require this type of advanced planning to ensure thatother industry members are not only willing to assist, but also are not prevented from assisting during thecrisis because paperwork is not in place, and therefore their lawyers advise against it.

Memorandums of Agreement and contracts for “mutual response aid” and emergency assistancewith other Operators and contractors should be required as part of any offshore well plan.

Other countries, such as Norway, Canada, and the USA, require oil spill plans and well control plans(including relief well and well capping plans) to be prepared, reviewed, and approved in advance of drilling and completion operations. The H1 oil spill plan was approved after the first phase of the wellwas drilled, and H1 relief well implementation was delayed while a rig was located and transported to thesite.

Drilling relief wells (or conducting well capping operations) is very serious, highly technical, dangerouswork. Plans for a relief well (or well capping operation) must be thought out in advance of drilling a well.

While a detailed, technical plan with exact specifications cannot be developed until an incident actuallyoccurs, the Operator can produce basic well control plans. The Operator can also pre-identify and pre-arrange terms with well control experts and relief well rigs. Negotiating with experts and rig Operatorswhile an emergency is occurring diverts the Operator’s response focus to contractual arrangements, whichdelays response and limits options.

358 State of Alaska Regulations at 18 Alaska Administrative Code, Chapter 75.




Well control of a catastrophic well blowout is serious, highly technical, dangerous work. Relief well and well capping plans should be developed prior to drilling a well. During a catastrophicemergency, there is insufficient time to be searching for well control experts, starting well controlplans from the beginning, or negotiating contracts for relief well rigs. This must be done inadvance to expedite emergency response.

PTTEP and ALERT Well Control recommended deluge and well capping operations that may haveexpedited H1 well control; however, according to PTTEP’s testimony, both were reportedly stalled orstymied by NOPSA. 359 This problem emphasizes the fact that it is not only important for industry have anemergency response plan that is thought out in advance, but there also needs to be government support forthat plan. Deluge and well capping operations are standard well control techniques. Agency staff shouldbe trained and qualified to know when to use these techniques, and should be capable of quick decisionmaking to ensure that the window of opportunity for using these techniques does not expire duringprotracted deliberations.

Advanced agency approval of emergency response plans enables quick decision making, ensuring

that the window of opportunity for implementing well control techniques does not expire duringprotracted deliberations.

4.37 Lack of Engineering and Technical Resources

Not only was PTTEP under-resourced while drilling the Montara wells, it was also under-resourcedduring the response. PTTEP testified that it had a hard time keeping up with all the requirements of responding to the emergency, running its other Australia operations and assisting in the incidentinvestigation. 360 Yet, PTTEP did not hire additional personnel or request additional resources from thePTTEP CEO. 361 The PTTEP Australasia CEO (Mr. Jacobs) testified that he retained 60% of his normalduties and took on all of the oversight responsibilities for the relief well and emergency response

operation.362

Not only was PTTEP under-resourced while drilling the Montara wells, it was also under-resourced during the response.

In addition to managing the Montara well blowout and oil spill response, PTTEP was also operating twoFloating, Production, Storage and Offloading facilities (FPSOs) in the Timor Sea. 363 The FPSOs are theJabiru venture and the Challis venture, which are located about 70 miles from the Montara field. PTTEPis the Operator of both FPSOs, on behalf of a joint venture. PTTEP also has joint ventures with Murphyoil and gas and Woodside. 364

PTTEP assigned the Montara Well Construction Manager (Mr. Duncan), along with most of the otherPTTEP and Atlas Drilling Staff 365 that were involved in the H1 blowout, to drill the H1 relief well and

359 Commission of Inquiry Transcripts, April 12, 2010, p. 1907-1909360 Commission of Inquiry Transcript, April 12, 2010, p. 1844-1848361 Commission of Inquiry Transcript, April 12, 2010, p. 1863362 Commission of Inquiry Transcript, April 12, 2010, p. 1882363 Commission of Inquiry Transcript, April 12, 2010, p. 1840364 Commission of Inquiry Transcript, April 12, 2010, p. 1925365 Commission of Inquiry Transcript, April 12, 2010, p. 1837




conduct emergency response activities. 366 Good oilfield practice would have been to grant leave to staff that were involved in the events leading up to the blowout, because they would have been understandablyvery shaken and not in good condition to do complicated, dangerous, and serious response work.

Additionally, leave would have given the staff involved in the events leading up to the blowout time tothink through what might have caused the blowout, which is essential information for the well controlteam drilling the relief well. It is of concern that the staff involved in the blowout played such key roles insubsequent response operations. This concern is highlighted by Mr. Treasure’s testimony that said he wasnot sleeping well and was seriously shaken. His supervisors should have observed this behavior, grantedleave and put another expert in place to drill the relief well.

PTTEP assigned staff involved in the H1 blowout to drill the H1 relief well and conductemergency response activities. Good oilfield practice would have been to grant leave to the staff that were involved in the events leading up to the blowout, because they would have beenunderstandably very shaken and not in good condition to do complicated, dangerous, and seriousresponse work.

The Well Construction Group did not have enough drilling and completion engineers. This was evidencedby the fact that Drilling Superintendent (Mr. Wilson) took on many job roles and responsibilities thatwould normally be assigned to a staff drilling engineer, causing Mr. Wilson to get behind on critical pathengineering questions, QA/QC work, and permits. The fact that Mr. Wilson was overwhelmed by theamount expected of him manifested in filing late permits and not responding to Mr. Treasure’s request forhelp in checking cement calculations. 367

Also, the rig lacked a trained, experienced, college educated drilling engineer to focus on complexengineering calculations, identify problems, help with solutions, and stay in touch with the onshoreengineer to make sure that the job was executed properly. Often rig supervisors and tool pushers are notcollege educated; nor do they have actual engineering experience with hydraulic and well constructioncalculations. Even if they do have college experience, rig supervisors and tool pushers are so consumed

with daily operations they often do not have time to step-back and focus on engineering solutions orconduct quality assurance and quality control.

Typically one or more experienced drilling engineers are usually located on the rig for support. Somecompanies have multiple drilling engineers on the rig to provide redundancy and 24 hours of coverage.The drilling rig engineer designs the barrier systems and testing programs, and is involved in securingpermits, or at least preparing the paperwork to secure permits, and verifying compliance with the permits.Mr. Treasure referred to Mr. Loveless as the drilling rig engineer, but said that he was a “trainee” withlittle experience. 368 There was no other testimony to show that a trained, experienced, college educated drilling engineer was located on the rig to support the Montara Well Completion and Tie-in program.

There was not enough engineering support out on the Montara Platform during drilling and

completion operations.

Atlas Drilling Manager (Mr. Gouldin) was transferred to the Montara Project on March 1, 2009, just asH1 was being completed. Mr. Gouldin’s Witness Statement said:

366 Commission of Inquiry Transcript, April 7, 2010, p. 1618367 Commission of Inquiry Transcript, March 30, 2010, p. 1268368 Commission of Inquiry Transcript, May 16, 2010




“From 1 March 2009, I began to take over the role of Operations Manager for Seadrill inSingapore. I was fully operational in that position from 21 March 2009. During the period 1 to21 March 2009, I was shadowing my predecessor in this role.” 369

Major changes of drilling personnel should be avoided during critical stages in a drilling program.Changes in Atlas management during the time of the H1 well completion (March 7) could havecontributed to the lack of technical oversight and communication errors.

4.38 Operator and Contractor - Training and Qualifications

Even with the PTTEP Well Construction Manager (Mr. Duncan), who is the most senior member of PTTEP Management, on the rig, faulty decisions were still made. 370

Mr. Jacobs (PTTEP CEO Australasia) testified that upon review of the H1 incident, he has concerns aboutthe expertise and decision making of PTTEP Management and contractors:

“Q. The final topic, and I think we're up to number 13, sir, in relation to issues canvassed in thecourse of these proceedings that might have added to your understanding of the position,concerns the topic of deficiencies in expertise .

A. Okay.Q. Do you have any inkling at all as to what I might be adverting to?

A. I have my views. I'm not sure what you're referring to, but I have my opinions regarding the competency of some of the personnel that were involved and their understanding of what should have been done and what was required to be done. Yes, if those are along the same lines, then

yes.Q. I think we are heading in the same direction, but as unsavoury as it might be, sir, I want you toactually particularise what it is that you have in mind in giving that answer?

A. Okay. Mr Treasure did not come across to me as a person in which I would have a great deal of confidence in the future …Then, as we’ve been through with Mr. Wilson and Mr. Duncan not being thorough enough on checking the relevant information that they had, whichwould have alerted them to the incidents is of concern.” 371

Mr. Jacobs (PTTEP CEO Australasia) testified that there were systemic problems with the WellConstruction Group’s implementation:

“Q. Sir, I want to suggest that, despite what you've said, we really are pretty much located in the terrain of endemic or systemic sloppiness; will you agree with me ? A. There's been failures in the systems and by the personnel, yes .” 372

While several layers of management are in place at PTTEP, Halliburton, and Atlas, the type of QualityAssurance (QA)/ Quality Control (QC) processes in place is not clear. QA/QC is needed to reviewdrilling rig and platform activities to ensure they are consistent with the well plan and permits. Theoversight and review processes seem very ad-hoc.

369 Commission of Inquiry Document, WIT.1501.0001.0001370 Commission of Inquiry Transcript, April 7, 2010, p. 1656371 Commission of Inquiry Transcript, April 7, 2010, p. 1672372 Commission of Inquiry Transcript, April 7, 2010, p. 1692




Companies should have written QA/QC protocols and staff should be trained to implement them.

Mr. Jacobs (PTTEP CEO Australasia) testified there were major changes in staffing during the MontaraWell Program Installation. Mr. Duncan Clegg was the Montara Project Manager up to Feb 2009; theorganization was Coogee Resources up to that time. PTTEP bought out Coogee and changed the

company’s name. In February Khun Narongpol took over for Clegg, and Clegg stayed on for a fewmonths to aid the transition. In September 2009 the Well Construction Group was transferred over to theoperations group led by Mr. Jacobs. Previously the Well Construction reported up through the MontaraProject Team. 373

In addition to a corporate buyout and transition, The Montara Well Program Installation underwent amajor change in Montara Program Management and the drilling supervision and engineering team wasmade up of contract staff.

Mr. Jacobs (PTTEP CEO Australasia) stated:

“ I fully acknowledge that there were failings in the systems and personnel both of the company

and also of contractors [emphasis added]…374

and that… when we started Montara, we were basically developing a new well construction department …375

The Safety Case Review included a commitment to ensure that Third Party Support Contractors hired byPTTEP are competent. 376 While several staff had decades of experience, there were multiple instances of:1) very experienced staff serving in new unfamiliar assignments, 2) “trainees” with little experience, and3) staff that may not be qualified for their roles despite years of experience. For example:

Neither Halliburton Staff (Mr. Doeg or Mr. Gestes) were familiar with standard proceduresfor setting cement plugs in horizontal hole sections; 377

Mr. Doeg (Halliburton Cement Staff on Rig) was not familiar with the use of density logs ortemperature logs as a diagnostic tool; 378

Most rig staff were not familiar with Australia’s regulations;

379

Mr. Treasure (Drilling Rig Supervisor) had not run a PCCC in nearly 20 years 380 and hadonly served once prior (for two weeks) as a rig supervisor, in the Philippines; and 381

Mr. Loveless (Logistics and Drilling Engineer) had “minimal” experience and was a“trainee.” 382

There was ample evidence unveiled during the Commission of Inquiry to show problems withThird Party Support Contractor’s training and qualifications.

Most of the drilling rig staff who testified denied any knowledge or understanding of Australianregulations regarding offshore drilling. Other countries require permits to be on location and be provided

373 Commission of Inquiry Transcript, April 9, 2010, p. 1760374 Commission of Inquiry Transcript, April 9, 2010, p. 1763375 Commission of Inquiry Transcript, April 9, 2010, p. 1774376 Commission of Inquiry Document, PTT.9000.0009.0239377 Commission of Inquiry Transcript, March 19, 2010, p. 416.378 Commission of Inquiry Transcript, March 19, 2010, p. 425379 Commission of Inquiry Transcript, March 19, 2010, p. 451380 Commission of Inquiry Transcripts, March 18, 2010, p. 354381 Commission of Inquiry Transcripts, March 19, 2010, p. 374382 Commission of Inquiry Transcripts, March 18, 2010, p. 269




to operator staff and contractors who are performing the tasks required by the permit. This is not currentlythe case in Australia.

Offshore supervisors should be familiar with the permits governing the operations they’reoverseeing; the permits should be on board; and offshore supervisors should have at least a basicunderstanding of regulatory requirements and a full understanding of permit limits. This enablesrig staff to make on-the-spot decisions, without violating permit conditions

Below is an example of the prescriptive qualifications and training standards that used to be in place inAustralia for blowout control, listed at Section 508 of The Schedule of Specific Requirements as toOffshore Petroleum Exploration and Production :

“(1)Blow-out prevention drills shall be conducted weekly for each drilling crew to ensure that allequipment is operating and that crews are properly trained to carry out emergency duties.

(2) All blow-out prevention drills and response times shall be recorded in the drillers log.

(3)

There shall be displayed on the rig floor a notice providing details of the well control procedures proposed to be followed in the event that indications of a well kick are observed and all drilling crews shall be trained in those procedures.

(4) All on-site personnel holding the position of derrickman or more senior, shall attend, at least once every 24 months, an accredited well-control school or refreshers course in well-controland obtain a certificate of proficiency from such school or course. ”

In addition to blowout control, there were numerous other training programs that were required for rigstaff; these should be reinstituted.

Regulations should specify the rig staff training and qualifications needed to safely operate

offshore.

4.39 Agency Decision Making and Oversight

The Designated Authority (DA) for the Territory of Ashmore and Cartier Islands offshore area wasdelegated to the Northern Territory Department of Regional Development, Primary Industry, Fisheriesand Resources (DRDPIFR). The DA denied any responsibility in the blowout, maintaining:

“It is the Territory’s primary submission that: at all material times prior to the uncontrolled release, the Territory appropriately administered the license area within which the Montara wellhead platform is located…[emphasis added]” 383

The DA acknowledged responsibility for:

“…the assessment and approval of drilling programs, well operation management plans, and environmental plans submitted by the operator (PTTEP) for the purpose of bringing the Montara-

H1 well under control.”

383 DA, Submission No. 4000.0001.0002




The Commission questioned Mr. Duncan (PTTEP Well Construction Manager) about whether they werescrambling out on the rig because of insufficient staff and time. Mr. Duncan responded that drilling isalways busy, while agreeing the March 6 afternoon request to the DA for H1 well suspension was notgood planning.

Mr. Duncan disagreed with Mr. Wilson’s conclusion that if the H1 plan was not approved on March 6,2009 by the DA, it would have put two days of rig time at risk ($1.2MM), because in that case PTTEPwould have fallen back to the original plan of setting a cement plug, and not just sat idle. 393

Permit approvals should only be granted by agency staff with the requisite decision makingauthority. Permit decisions should be based on a technically sound analysis of permitapplications.

According to PTTEP’s submission, the original H1 well permit approval of November 2008 requiredcement plugs to be placed in the 9-5/8” intermediate casing string as part of the abandonment procedure.PTTEP stated that:

“At the time of the March 2009 suspension, an amendment to the Drilling Program wasimplemented by the Well Construction Manager and Drilling Superintendent (in accordance withthe Change Control requirement in the Well Construction Standards) to replace the 244mm

cement plug with the 244mm pressure containing corrosion cap and the 340mm pressure containing corrosion cap [emphasis added].” 394

Oddly, the DA concluded that removing the cement barrier from the well suspension plan would not“affect the physical aspect of the wellbore. ” The DA stated:

“On 6 March 2009, PTTEP submitted an application for the Stage 1 suspension of the Montara H1-ST1 well and advice of a change to the well plug from cement to a pressure containing cap.The Director of Energy as delegated of the Designated Authority determined that the change to

the well plug did not affect the physical aspect of the wellbore so as to attract application of reg17(1) of the Petroleum (Submerged Lands ) (Management of Well Operations) Regulations

2004 , and no further approval was necessary for that purpose…Approval was subsequentlygranted pursuant to reg 17(1)(d) in accordance with the PTTEP letter of 6 March2009… 395[emphasis added].”

This explanation from the DA is confusing because Reg 17(1) requires DA approval for any change to awell suspension plan. PTTEP submitted a change to a well suspension plan pursuant to Reg 17(1), and theDA ultimately approved it after the well was actually suspended.

Under Australian Petroleum (Submerged Lands) (Management of Well Operations) Regulations 2004 at§17 (1)(d) a well may not be physically suspended until the suspension procedure is approved by the DA.

“17 Approval(1) A titleholder must not commence any of the following well activities, that lead to the physical

change of a wellbore, without the approval of the Designated Authority:(a) well drilling;

393 Commission of Inquiry Transcript, March 30, 2010, p. 1370 394 PTTEP, Submission No. 1000.0001.0045395 DA, Submission No. 4000.0001.0017




(b) testing;(c) well completion;(d) abandonment or suspension of a well ;(e) well intervention[emphasis added].”

During the Inquiry the Commissioner questioned the DA about whether it was more concerned withissuing hurried approvals to avoid delaying the rig than conducting a thorough technical review.

“In your view, avoiding that possibility – the rig sitting largely idle while you’re considering an application is a very undesirable consequence …” “ I suggest that factor was of greaterinfluence to you in considering the application on 6 March than t he need to properly and

carefully consider whether it represented good oilfield practice and would ensure well integrity [emphasis added].” 396

While the DA Staff (Mr. Marozzi) rejected the Commission’s premise, no evidence was provided tosupport this objection. DA Staff then testified that they believe the current Australian regulations put theonus of using good oilfield practice and verifying compliance on the Operator (“self regulation”), and it isnot the DA’s role to “micro-manage,” even on matters as important as well control barriers.

“Q. Do you agree that it would have been preferable, prior to your recommending approval of the stage 1 suspension, for you to take steps to satisfy yourself that the basic cementing standards I just took you to either had occurred or would occur? A. Yes, if I'm going to micro-manage the operator , yes, sure.Q . And you think that taking such steps to ensure that the only barrier in the annulus and one

of only two barriers in the inside casing string satisfied those requirements is micro- management; is that right? A. Yes, I believe so , according to the Commonwealth regulations as they are currently prepared, yes.Q. Do I therefore take it to be your evidence that you don't think it's the DA's responsibility to

take such steps? A. I don't believe it is the DA's responsibility to micro-manage a company with a good track record [emphasis added].” 397

“Q. Do you think, reflecting upon your work in the last couple of years, there is a risk that you came to see yourself more there as a facilitator of what operators such as PTT wanted to do, rather than carefully scrutinizing their activities in order to be completely satisfied that they constituted good oilfield practice? A. I wouldn't put it that way. It's fair to say that I could have relaxed on the micro-management because of their very good track record before Montara H1 [emphasis added].” 398

“Q. What about prior to approving the application for stage 1 suspension - did you take any

steps to ensure that such matters would be done safely? A. Well, the regulations don't require those exact steps to be included in the application tosuspend.Q. So the answer to my question is, no, you didn't take any steps to ensure that such matterswould be done safely; is that right?

396 Commission of Inquiry Transcript, April 13, 2010, p. 2038-2039397 Commission of Inquiry Transcript, April 13, 2010, p. 2054398 Commission of Inquiry Transcript, April 13, 2010, p. 2061




A. That's correct, yes . [emphasis added].” 399

Applications should be submitted for agency approval prior to completing work. Applicationsshould be submitted with adequate time for the agency to complete a technical review. After-the-fact permit approvals should not be granted by the agency.

The DA is responsible for reviewing and approving the Well Operations Management Plan (WOMP). DAStaff testified that they rely on the basic engineering standards in the now revoked Schedule of Specific

Requirements as to Offshore Petroleum Exploration and Production, because there has been no otherdecision making guidance, procedures or instructions issued to staff.

In its submittal to the Commission, the DA provided a full copy of the pre-existing Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production (replaced in 2004 by the moregeneric “good oil field practices” showing standard), but did not explain in its submittal, nor later intestimony, why it chose to deviate from these standards in the H1 approval. It remains unclear why theDA approved a well suspension plan without the placement of additional cement plug barriers, and thenallowed re-entry into a well with a known compromised cement job while no surface pressure control

system was in place.

There was no evidence of any substantive technical review completed by the DA when decidingto allow a PCCC to replace a cement plug. There was no evidence that the DA was familiar withthe technical capabilities and risks of PCCCs.

Other oil and gas producing countries use a two-tier regulation process. Regulations contain minimumprescriptive standards that serve as a regulatory “floor.” Then, “good oil field practice” is applied to theseminimum prescriptive standards through an Operator demonstrating in an application that a technique orpractice exceeds the “floor.” This method is founded on the idea of “best practice.”

For example, Norway’s regulations 400 allow new technology and methods to be used, but require carefulreview and testing of those methods before use.

“Section 8, Qualification and use of new technology and new methods

Where the petroleum activities involve use of new technology or new methods , criteria shall be prepared with regard to development, testing and use in order to fulfill the requirements to health, environment and safety . The criteria shall be representative of the relevant operationalconditions, and the technology or the methods shall be adapted to already accepted solutions.

Qualification or testing shall demonstrate that applicable requirements can be fulfilled by use of the relevant new technology or new methods [emphasis added].”

The DA’s submittals to the Commission of Inquiry do not reference any engineering manuals,databases, lists, or regulatory guidance documents that Staff relied on to make the determinationthat the Montara H1 applications met the “good oilfield practices” standard.

399 Commission of Inquiry Transcript, April 13, 2010, p. 2067400 Relating to Design and Outfitting of Facilities in the Petroleum Activities (“The Facilities Regulations”) of the Petroleum Safety AuthorityNorway (PSA), Norwegian Pollution Control Authority (SFT), Norwegian Social and Health Directorate (NSHD).




Even in light of the H1 blowout, the DA made an astounding conclusion in its submission to the Inquiry –one that was absent of any citation to documented, accepted technical standards, engineering manuals, orinternational best practice policies:

“ The Territory has not identified any matter that would suggest poor design in the equipmentemployed by PTTEP [Emphasis Added].” 401

A written technical engineering assessment of the Montara H1 well applications and an agencydecision of fact and finding were nowhere to be found in the hundreds of pages of agencysubmittals and exhibits to the Commission of Inquiry. The DA submittals asserted that “good oilfield practice” was met, but no technical documents or other evidence to support that conclusionwas provided.

The entire Montara well planning effort was constrained by a short timeframe, because a major latechange in platform facility installation plans triggered major changes in well design. Also, a transition of Operators contributed to hasty well planning. The well plan was submitted just two months prior to spud.H1 was spudded 402 on January 18, 2009, 403 and the well plan was submitted to the DA on November, 7

2008.

PTTEP stated that well H1 was drilled and completed according to the following documents: 404

PTTEP’s Drilling Program entitled “Montara GI, H1 & H4 (Batch Drilled) Drilling ProgramDocument Number TM-CR-MON-B-150-00001 Rev 0” dated September 2008 .

PTTEP Well Operations Management Plan Document for H1 Number TM-CR-MON-G-150-00002Rev 0 dated November 7, 2008 , approved 8 business days later on November 19, 2008. 405 Thisapplication is for the Top Hole Section of the well only, up to and including setting the 244mm (9-5/8”) intermediate casing and then temporarily suspending the well until the Topside Module wasavailable for the well to be tied-in.

The DA reported a revision to the Batch Drilling Program for wells H1, GI and H4 was submitted onJanuary 7, 2009 .406 PTTEP did not list this permit application. The DA did not state when thisrevision was approved, or what the design change entailed. This revision came only 11 days beforeH1 was spudded on January 18, 2009. The DA stated that this revision did not “…affect the physicalaspect of the wellbore, so no further approval was necessary.” 407 The purpose and the nature of theJanuary 7, 2009 amendment are unclear, and warrant further review. As no H1 applications oramendments were provided for public review, it is not possible to independently examine thesignificance of the January 7, 2009 change.

PTTEP submitted applications to suspend H1 on March 6, 2009 and March 12, 2009 .

PTTEP only provided the dates that the H1 well suspension applications were submitted to the DA; itdid not disclose when they were approved. However, the DA disclosed the date it approved the H1suspension application; it was March 9, 2009 , two days after the well was actually suspended. 408

401 DA, Submission No. 4000.0001.0009402 Commenced drilling.403 PTTEP, Submission No. 1000.0001.0034404 PTTEP, Submission No. 1000.0001.0033405 DA, Submission No. 4000.0001.0013406 DA, Submission No. 4000.0001.0013407 DA, Submission No. 4000.0001.0016408 DA, Submission No. 4000.0001.0014




The DA listed a subsequent approval on March 13, 2009 , approving a second amendment to a wellsuspension procedure for a well that already had been physically suspended 6 days (March 7, 2009).

The first phase of the H1 well was drilled without the required DA approved Environment Plan.

The DA reported that it received a letter from PTTEP on April 8, 2009 seeking confirmation as towhether or not the Montara H1 Environment Plan had been approved. The DA reported that theEnvironmental Plan was assessed by the Senior Petroleum Operations Officer, who recommended to theDirector of Energy that the plan be approved. Approval was granted on April 9, 2009 . Therefore, theEnvironment Plan for H1 was approved three months after the well was spudded on January 18,2009. This was the second after-the-fact approval made by the DA for H1. There is no value in an after-the-fact Environment Plan.

The H1 oil spill plan was not approved by DEWHA until March 6, 2009, after the first phase of the well was drilled.

Oil spill plans and well control plans (including relief well and well capping plans) should have beenprepared, reviewed, and approved in advance of drilling and completion operations. The H1 oil spill planwas not approved by DEWHA until March 6, 2009. Phase 1 drilling for H1 started on January 18, 2009and ended on March 7, 2009. This mean there was no approved oil spill plan in place during that time.

PTTEP reported that it submitted the “Montara Phase 1B Drilling and Completion Program DocumentNumber TM-CR-MON-B-150-00003 Rev 0” in June 2009. This document served as the drilling programpermit application for the horizontal reservoir sections of the H1 well. This application covered the re-entry into H1 to tie in the well. It also covered drilling out the remaining section of the well, passingbeyond the 9-5/8” casing and into the production zone.

The DA listed this permit application as being received on July 7, 2009. The DA showed that it issued arapid approval in only four business days, on July 13, 2009. 409 The quick turnaround brings into questionthe thoroughness of the DA’s technical review, and explains why no other agencies’ opinions were soughtfor peer-review (but should have been).

H1’s phase 2 re-entry plan was approved in four business days, with no apparent technical orsafety peer review by RET or NOPSA.

PTTEP’s submittal 410 stated that the Montara Wellhead Platform was installed in July 2008, and inSeptember 2008 the West Atlas drilled and grouted the remaining piles for the jacket of the MontaraWellhead Platform. However, rather than staying at the Montara Wellhead Platform, from October 2008to January 2009, the West Atlas carried out drilling operations for Vermillion and PTTEP at otherexploration well locations .411

Between January 2009 and April 2009, the West Atlas batch drilled the Montara production wells (H1,H2, H3, H4) 412 and gas injection well (GI) down to the 244mm (9-5/8”) casing, and then suspended eachwell. 413

409 DA, Submission No. 4000.0001.0013410 PTTEP, Submission No. 1000.0001.0033411 PTTEP, Submission No. 1000.0001.0034412Atlas Drilling, Submission No. 1501.0001.0002413 PTTEP, Submission No. 1000.0001.0034




On April 21, 2009 the West Atlas left the Montara Wellhead Platform to conduct exploration drilling atother locations .414

On August 19, 2009 the West Atlas returned to the Montara Wellhead Platform to tie in H1, H2, H3, H4,and GI wells .415

PTTEP’s submittal to the commission 416 stated that there was no inspection or audit of: the MontaraWellhead Platform, the drilling rig operations while the West Atlas was over the Montara WellheadPlatform, or the well configuration after the wells were suspended , and that “no enforcement actionhad been taken by any regulator in relation to the drilling work” 417 on the Montara Wellhead Platform.

PTTEP stated that NOPSA did conduct an inspection of the West Atlas rig from October 6-9, 2009 andthat an Improvement Notice was issued by NOPSA relating to the electrical equipment voltage. 418 Thisclearly indicates that NOPSA’s safety review scope does include rig related activities, which is a pointNOPSA tries to distance itself from in its submittal.

According to the timeline provided by PTTEP, the NOPSA inspection occurred while the West Atlas wasdrilling at other exploration well locations. Thus, it appears that NOPSA inspectors did not inspect theWest Atlas while at the Montara Wellhead Platform.

PTTEP also noted that the Australian Commonwealth Department of Environment, Water, Heritage andthe Arts (DEWHA) wrote to PTTEP on January 22, 2009 advising of a potential audit of the Montara 4,5, and 6 wells under the Environmental Protection and Biodiversity Conservation Act of 1999 (EPBCAct). 419 That audit did not occur prior to the Montara H1 well blowout.

PTTEP stated that it invited the DA to conduct an onsite audit, but no date was provided for when thatinvitation was given. PTTEP confirmed that the DA audit did not take place prior to the Montara H1 wellblowout. 420

The DA reported that it:

“… does not conduct physical inspections of operations or well infrastructure during routineoperations [emphasis added].” 421

If the DA does not inspect well operations, then the question is: which Australian agency does conductthese important compliance inspections?

The DA argued that:

“…in line with contemporary regulatory practice the Territory does not conduct physicalinspections of drilling and wellhead infrastructure during routine operations. The onus is on the

operator to conduct its operations according to approved plans and work programs. Given the

414 PTTEP, Submission No. 1000.0001.0034415 Atlas Drilling, Submission No. 1501.0001.0004416 PTTEP, Submission No. 1000.0001.0056417 PTTEP, Submission No. 1000.0001.0056418 PTTEP, Submission No. 1000.0001.0056419 PTTEP, Submission No. 1000.0001.0056420 PTTEP, Submission No. 1000.0001.0056421 DA, Submission No. 4000.0001.0003




‘round the clock’ nature of work on oil rigs, onsite monitoring would place a significant additional burden on both operators and regulators alike . [emphasis added].” 422

Shockingly, even after a catastrophic blowout of this magnitude, the DA argued that:

“…It would be possible to place government inspectors on rigs for the purpose of supervisingoperations and scrutinizing adherence to approved programs. The current regulatory regimeallows for the appointment and placement of a petroleum project inspector for that purpose. Asstated, however, that measure has not been adopted as part of the contemporary regulatory

practice for routine operations. The adoption of that measure [onsite inspections] would increase project and regulation costs, placing an additional burden on the ope rators and

regulators [emphasis added].” 423

DA Staff (Mr. Marozzi) testified:

Q. Well, if I were to tell you that the Inquiry has heard evidence that PTT did not, in fact, test orverify the PCCs in situ in the H1 well , would that cause you to change your practice in the future

Mr. Marozzi? A. Possibly, if I was aware of it, it certainly would, but it's compliance monitoring, and the regulations place the onus of compliance monitoring on the operator [emphasis added].” 424

Agency inspection and oversight was inadequate for the Montara Platform and the MontaraDrilling and Completion Operations. Agencies should be responsible for compliance monitoring.

The Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production at § 513 historically provided very clear guidance on how to temporarily abandon a well.

Section 513 425 states:

“A well shall not be abandoned or suspended without prior approval, except as provided for insub-clause (4). 426 ”

“…Prior to the cessation of drilling operations, even temporarily, the well shall be made safe in accordance with good oil field practice ” [emphasis added].

“…Where casing is being installed, if a well encountered: (a) hydrocarbons ; (b) abnormally pressured water; (c) unstable coals or shales; (d) lost returns ; the drilling operations shall becontinued to the next scheduled casing point at which point the hole will be logged, cased and

secured at the surface ” [emphasis added].

“…An application for approval to abandon or suspend a well shall give the particulars of: (a)

the name of the well; (b) the reason for abandonment or suspension; (c) the proposed

422 DA, Submission No. 4000.0001.0012423 DA, Submission No. 4000.0001.0048424 Commission of Inquiry Transcript, April 13, 2010, p. 2046425 The Petroleum (Submerged Lands) Act 1967, Schedule: Specific Requirements as to Offshore Petroleum Exploration and Production – 1995;November 2005 Electronic Consolidation.426 Note: sub-clause (4) is an emergency or adverse weather clause that would not apply to the H1 well. Thus, the technique for suspending theH1 well would have required Australian government approval.




abandonment or suspension program including the method by which the well shall be made safe;(d) such further information as the Director may require.”

H1 well penetrated the hydrocarbon zone, encountered serious mud loss while drilling intermediatecasing, and was not properly secured at the surface with either a BOP or wellhead control system.

Section 514 of The Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production instructs cased wells to be abandoned as follows: 427

“ In a cased hole containing a liner string or strings, a cement plug shall be placed immediately above each liner string hanger to extend at least 30 metres above the liner string hanger. A surface cement plug extending at least 45 metres in height shall be placed in the innermost casing string which extends to the seabed with the top of the plug at a depth no greater than 45 metres below the seabed. The location and integrity of cement plugs shall be verified in an approved manner. Any intervals of cased hole in a well between cement plugs shall be filled with mud fluid of appropriate density suitably inhibited to prevent the corrosion of casing

string [emphasis added].”

Section 515 of The Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production requires wells to be suspended using Section 514 (unless otherwise approved) and:

“approved equipment and protection devices shall be installed on the well head to facilitate future re-entry of the well.” 428

These now revoked Australian standards include similar requirements to those found in the USA forsuspending wells, including: mechanical plugs, temporary cement, and surface wellhead controls.

Temporary suspension plans must be approved by authorities in both Australia and the USA.

Temporary well suspension requirements for the USA are described in the United States Department of

Interior, Minerals Management Service (MMS) Regulations at 30 CFR 250.1721, which require a cementplug at least 100’ long (30.48m) to be placed in the casing:

“§ 250.1721 If I temporarily abandon a well that I plan to re-enter, what must I do?You may temporarily abandon a well when it is necessary for proper development and productionof a lease. To temporarily abandon a well , you must do all of the following :

(a) Submit form MMS–124, Application for Permit to Modify, and the applicable informationrequired by §250.1712 to the appropriate District Manager and receive approval;

(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in §250.1715 , except for §250.1715 (a)(8). You do not need to sever the casings, remove the

wellhead, or clear the site;

(c) Set a bridge plug or a cement plug at least 100-feet long at the base of the deepest casingstring, unless the casing string has been cemented and has not been drilled out. If a cement plugis set, it is not necessary for the cement plug to extend below the casing shoe into the open hole;

427 The Petroleum (Submerged Lands) Act 1967, Schedule: Specific Requirements as to Offshore Petroleum Exploration and Production – 1995;November 2005 Electronic Consolidation.428 The Petroleum (Submerged Lands) Act 1967, Schedule: Specific Requirements as to Offshore Petroleum Exploration and Production – 1995;November 2005 Electronic Consolidation.




plug; or (E) A tubing plug set no more than 100 feet above the perforated intervaltopped with a sufficient volume of cement so as to extend at least 100 feet above the uppermost packer in the wellbore and at least 300 feet of cement in the casing annulus immediately above the packer.

(4) A casing stub where thestub end is within the casing

(i) A cement plug set at least 100 feet above and below the stub end;(ii) A cement retainer or bridge plug set at least 50 to 100 feet above thestub end with at least 50 feet of cement on top of the retainer or bridge

plug; or (iii) A cement plug at least 200 feet long with the bottom of the plug set nomore than 100 feet above the stub end.

(5) A casing stub where thestub end is below the casing

A plug as specified in paragraph (a)(1) or (a)(2) of this section, asapplicable.

(6) An annular space that communicates with open holeand extends to the mud line

A cement plug at least 200 feet long set in the annular space. For a wellcompleted above the ocean surface, you must pressure test each casingannulus to verify isolation.

(7) A subsea well withunsealed annulus

A cutter to sever the casing, and you must set a stub plug as specified in paragraphs (a)(4) and (a)(5) of this section.

(8) A well with casing A cement surface plug at least 150 feet long set in the smallest casing that extends to the mud line with the top of the plug no more than 150 feet below the mud line.

(9) Fluid left in the hole A fluid in the intervals between the plugs that is dense enough to exert ahydrostatic pressure that is greater than the formation pressures in theintervals.

(10) Permafrost areas (i) A fluid to be left in the hole that has a freezing point below thetemperature of the permafrost, and a treatment to inhibit corrosion; and (ii) Cement plugs designed to set before freezing and have a low heat of hydration.

(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity:

(1) A pipe weight of at least 15,000 pounds on the plug; or

(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Manager may require you to tests other

plug(s).”

In the USA, MMS regulations at 30 CFR 250.517 require surface pressure control (a blowout preventer orwellhead control system) and a subsurface safety valve to be installed in all offshore wells once they arecompleted. This way, if there is any failure of the surface wellhead control, the subsurface safety valveprovides a second, redundant safety measure to control the well.

If Australian regulators had requested PTTEP to delay drilling H1 until after the Topside Module was inplace, H1 could have been drilled from top to bottom with a BOP in place during the entire welloperation, and then it could have been safely tied-back into the Topside Module wellhead control system




for uninterrupted surface wellhead control. Additionally, a subsurface safety valve could have beeninstalled to provide an extra layer of prevention.

To be clear, if the well was tied-back into the wellhead control system when the West Atlas originallydrilled H1 in early 2009, a cement plug would not have been necessary for long-term suspension, becausethe wellhead control system would have provided the surface control system required by Australian (andsimilarly by USA) regulation. However, because the Topside Module was behind schedule and was notinstalled, H1 could not be tied-back into a wellhead control system when intermediate casing work wascompleted and the well was ready to be suspended. And since no BOP was left over H1, proper temporarysuspension required installation of a cement plug in the well to control pressure.

In March 2009, when the H1 well suspension plan was submitted for approval, the DA should haveknown, by inspecting the drillers logs, that: H1 penetrated 1,187m (3,894’) of hydrocarbon interval;encountered serious mud losses at 1,706m (8,560’); experienced an initially failed cement job; and had afailed 244mm (9-5/8”) intermediate casing shoe valve. This well clearly needed surface well control orthe installation of cement plugs to ensure continued, reliable, redundant well control.

The DA should not have approved the H1 well suspension permit because it did not contain a“two-barrier” control system. A waiver allowing cement barriers to be removed from the H1 wellsuspension plan was not technically justified, and was unsafe.

When questioned by the Commissioner about Operator insurance, Mr. Marozzi (DA, Senior Engineer)stated that one of his jobs is to ensure that adequate Operation insurance is in place, but he could notexplain how he determined this:

“Q. So do I understand, by your last answer, that, in your view, you can really leave it up to the operator to ensure they have appropriate insurance in place? A. If the figure is deemed as inadequate, we would have a conversation with the operator, but generally we leave it to the operator [emphasis added].” 429

Q. Do you know exactly what is covered and what is not covered by those types of insurance classes? A. On a general level I do, on a broad level.Q. But do you know on a specific level what they cover?

A. No, I don't know that information.Q. Would you know, for example, whether either of those insurance classes would cover the cost of water sampling or environmental monitoring in the event of an uncontrolled release of hydrocarbons?

A. I'd be guessing as to which of the two covered that.Q. Would you be guessing as to whether either of them covered it?

A. Yes.Q. Would you be guessing as to whether either of those insurance classes covered the costs of reimbursing fishermen who might be affected by any uncontrolled release of hydrocarbons?

A. Well, I would expect that would be covered under "third party".Q. Do you know?

A. I wouldn't be absolutely certain, no.

429 Commission of Inquiry Transcript, April 13, 2010, p. 1990.




Q. And do you know whether either of those insurance classes would cover tourist operatorswhose operations might be affected by an uncontrolled release of hydrocarbons?

A. Again, I would suspect it would be covered under "third party", but I wouldn't be certain.Q. Do you think you should take steps to inform yourself as to exactly what is and is not

covered by an operator's insurance before ticking off that aspect of the regulatory process, Mr. Marozzi? A. Well, it wouldn't hurt [emphasis added].” 430

“Q. Do you think that, in fulfilling the role as regulator of the offshore petroleum industry, itwould be an important thing that the Department of Resources could do to ensure that thatinsurance is in place?

A. Yes, it would be a positive thing to tighten up on that, yes [emphasis added].” 431

Financial responsibility requirements for offshore operators should be clearly articulated in theregulation such that agency staff can verify compliance.

Both NOPSA and DEWHA cited conflict of interest as a primary reason for considering the transfer of

well permit approvals from the DA to NOPSA or another agency. NOPSA cited findings from the PiperAlpha disaster that recommended safety oversight be divorced from the reservoir management aspect of the Petroleum Licensing regime, because there was a conflict of interest between maximizing therecovery of petroleum reserves and safety. 432

4.40 Agency Coordination

The DA claimed close coordination with other agencies:

“these assessments and approvals were conducted in consultation with the relevant Commonwealth agencies.” 433

The DA’s claim that multi-agency consultation was completed appears to be unsupported, basedon the records and submissions of the other agencies that provided information to theCommission of Inquiry.

NOPSA’s submission absolves itself of any oversight failures. NOPSA points out that the Petroleum(Submerged Lands) (Management of Well Operations) Regulations 2004 do not have a provision forreferring the Well Operations Management Plan (WOMP) to NOPSA for consideration or acceptance.NOPSA also reports that there is no “…legislative basis or arrangements which support or underpinNOPSA’s consideration of the safety related aspects of a WOMP.” 434 Yet, this statement appears to beinconsistent with a Memoranda of Understanding (MOU) that is in place between NOPSA and DA to“…facilitate the appropriate exchange of information, notification and reporting.” 435

Furthermore, the Guidelines for Offshore Well Operations (December 2004) clearly state that the DA isexpected to seek advice from NOPSA for any significant well safety issues:

430 Commission of Inquiry Transcript, April 13, 2010, p. 1992-1993. 431 Commission of Inquiry Transcript, April 13, 2010, p. 1994 432 NOPSA, Submission No. 3003.0001.0010433 DA, Submission No. 4000.0001.0243434 NOPSA, Submission No. 3003.0001.0007435 NOPSA, Submission No. 3003.0001.0007




“If the well activity involves any significant safety issues, the DA will seek advice from NOPSA ,under a Memorandum of Understanding (MOU) between NOPSA and the DA [emphasisadded]. ”436

Agencies should work cooperatively and professionally to ensure seamless oversight occurs foroffshore operations. There should be clarity on the point at which one agency’s responsibilitiesend and the other agency’s responsibilities begin.

Offshore Resources Branch, Resources Division, Commonwealth Department of Resources, Energy andTourism (RET) “Guidelines for Offshore Well Operations” state that if the WOMP or well activityinvolves any significant safety issue, the DA needs to seek advice from NOPSA. Furthermore, under theOffshore Petroleum and Greenhouse Storage Act (2006), DA also needs to consult with RET on drillingoperations that fall outside standard drilling technologies and practices, among a list of other things.

“Proposals and activities falling outside standard drilling technologies and practices are referred to RET (and from there to other Commonweath bodies such as Geoscience Australia)

for additional technical input before any determination on the application is made” [emphasisadded]. 437

Furthermore, the Offshore Petroleum and Greenhouse Storage Act (2006) requires:

“Major changes…to be evaluated by both the Director and RET and received acceptance prior tobeing adopted” [emphasis added]. 438

Batch drilling and delayed Topside Module installation were “major changes” to the development plan.Yet, there are no records to show a technical peer review and consultation was initiated was completed.According to RET’s submission, this peer review did not occur. DA is silent on this topic.

The DA did not consult with RET or NOPSA before making major changes to the wellcompletion and suspension plan. This action conflicts with Australia’s Guidelines for OffshoreWell Operations that direct the DA to consult with NOPSA and RET.

4.41 Agency - Training and Qualifications

Approving a plan that does not have continued, reliable, redundant well control is inconsistent with “goodoil field practice” and thereby inconsistent with Australian regulations. This brings into question thequalifications and training of the personnel reviewing and approving the well suspension applications.

A regulatory system that relies on good oilfield practice, rather than a prescriptive list of minimum standards, requires trained, qualified, and experienced staff capable of reviewing andapproving alternative procedures.

436DA, Submission No. 4000.0001.0237437 DA, Submission No. 4000.0001.0067438 DA, Submission No. 4000.0001.0158




The DA reported it has:

“…professional staff with an understanding of the practical approach required under thislegislation.”

The DA went on to conclude:

“…appropriate qualifications and industry experience to undertake regulatory approvals and monitoring processes supported by effective internal structures are key to this.” 439

Yet, testimony revealed the DA did not have a sufficient number of trained and qualified staff normanagement to effectively and safely oversee offshore oil and gas well operations.

DA did not have a sufficient number of trained and qualified staff nor management to effectivelyand safely oversee offshore oil and gas well operations.

The training and qualifications of DA Staff were questioned by the Commissioner. Mr. Marozzi (DA,

Senior Engineer) said he worked offshore for seven years from 1985 to 1992, and then taught high schoolfrom 1992-2006. He said he was hired by the DA in 2006 and later promoted to a senior energy engineerto provide technical review of WOMPs and other permits. Mr. Marozzi testified that he had not receivedtraining or certifications in well control or regulatory approval matters during his three (3) years at theDA.

“Q. You started the position as senior energy engineer in August 2007? A. That's right.Q. Could you tell the Commissioner what, if any, training you have received in relation to well

management operations or regulatory matters since holding that position? A. There has not been any. Q. None whatsoever?

A. No [emphasis added].”440

When questioned by the Commissioner about his training and expertise for conducting WOMP technicalreviews, Mr. Marozzi testified:

“Q. What training or experience do you consider you have that enables you to properly assessenvironmental impacts of certain drilling activities?

A. In that context, it's pretty much self-taught , with a scientific background, I guess, but as anengineer, and then I probably learnt far more about the broadness of the topic as a scienceteacher, and then furthermore, on-the-job training in this role - in this context, that is. [emphasisadded].” 441

Mr. Whitfield was the official delegate of the DA who had the authority to approve WOMPs and otherpermits. However, Mr. Marozzi, who reported directly to Mr. Whitfield, testified Mr. Whitfield did nothave the technical background to complete the reviews of WOMPS and permits. Mr. Whitfield’sstatement corroborates that he essentially accepted Mr. Marozzi’s recommendations.

“Q. I think Mr. Whitfield says in his statement words to the effect that you really assessed the

439 DA, Submission No. 4000.0001.0012440 Commission of Inquiry Transcript, April 13, 2010, p. 1950 441 Commission of Inquiry Transcript, April 13, 2010, p. 1950




applications and made a recommendation to him, and he acted on the basis of your recommendation. Is that a fair summation of how the process worked? A. Yes, that's correct.Q. Would it be fair to say that Mr. Whitfield didn't have, in your view, the technical skills orexperience to independently assess the applications himself without input or assistance from

you? A. That's correct [emphasis added].” 442

Mr. Marozzi (DA, Senior Engineer) testified that his supervisors, Mr. Whitfield and Mr. Holland (whooccasionally served in Mr. Whitfield’s position), did not have any offshore experience or technicalexpertise, nor did they provide any technical oversight, quality contro l or independent technical decisionmaking.

“Q. So it got to the point, I suggest, that when you did recommend something for approval to Mr. Whitfield or Mr. Holland, they accepted your recommendation on each and every occasion ; is that right? A. I can't recall a time that they didn't, that's right .Q. Can you recall a time when they engaged in detailed conversation about technical aspects of

the application with you before approving it? A. I can't recall a time. [emphasis added].” 443

Mr. Whitfield (DA, Director of Energy) confirmed that he approved the use of a PCCC as a barrier onMarch 9, 2009 and March 12, 2009 without a technical understanding of whether a PCCC meets the goodoilfield standard for well barriers:

“Q. Did you , in February last year, have any understanding of whether pressure-containing corrosion caps were generally used by the offshore petroleum industry or not? A. No .Q. So I take it that you didn't have any understanding about, if they were used, what they wereused for, typically; is that right?

A. That's correct.Q. So is it the case that you had no knowledge or understanding whatsoever about pressure-

containing corrosion caps as of February last year? A. That's correct [Emphasis Added].” 444

Mr. Whitfield (DA, Director of Energy) didn’t deny his lack of technical ability, and agreed he relied onMr. Marozzi to make approval decisions:

“Q. That wasn't quite my question, Mr Whitfield. My question was whether you agree with hisevidence to the effect that he was the only person in the department with the sufficient skills

and experience to undertake an analysis of the technical aspects in a drilling application ? A. Within the energy operations area, yes . I can't speak for the whole department. I suspect so

[Emphasis Added].”445

Mr. Marozzi (DA, Senior Engineer) testified that he is the only engineer at the DA, and that this cancause problems when he takes his 5 weeks of annual vacation, because it leaves technical decisions in thehands of Mr. Stuck who isn’t qualified to review and approve the engineering portions of applications. 446

442 Commission of Inquiry Transcript, April 13, 2010, p. 1957 443 Commission of Inquiry Transcript, April 13, 2010, p. 1958 444 Commission of Inquiry Transcript, April 15, 2010, p. 2239445 Commission of Inquiry Transcript, April 15, 2010, p. 2239




DA Staff acknowledged failings in barrier decisions. Mr. Marozzi testified:

“Q. I suggest that's a fairly damning indictment on your level of understanding , Mr Marozzi,having made those statements, in light of the evidence that I have taken you to. What do you sayabout that?

A. At the time, that was my level of understanding, so, yes, my understanding was limited, I agree .” 447

“Q. Do you accept that that betrays a fundamental lack of knowledge and understanding on your part in relation to well integrity matters , Mr. Marozzi? A. It betrayed a lack of understanding of what really happened here.Q. And that lack of understanding about what had happened suggests a lack of understanding

of basic well control principles ; do you agree? A. It can be argued that way, yes .” 448

“And that's a very real cause for concern about the competence of the Northern Territory to fulfil a regulatory function in relation to the offshore petroleum industry ; agreed?.” 449

While Mr. Marozzi agreed additional training should have been provided by the DA, he also stated that hecan’t leave for training because there is no one else available to do technical reviews. 450 Mr. Marozzitestified that the DA is understaffed and under-resourced. 451

Mr. Marozzi testified that he takes pride in the DA’s speed for conducting reviews and approvals; henoted that he has never kept a rig waiting. 452

While several layers of management are in place at DA, most members of management are not qualifiedto provide technical review and oversight. Furthermore, the Quality Assurance (QA)/ Quality Control(QC) processes in place are not clear. QA/QC is needed to review drilling rig and platform activities toensure they are consistent with the well plan and permits. The agency oversight and review process seemsvery ad-hoc.

Agencies should have written QA/QC protocols and staff should be trained to implement them.

The DA was essentially “rubber stamping” permit applications with very little technical review. TheCommission showed evidence that Mr. Marozzi’s assessments rarely contained any detailed technicalreview, and usually just included words to the effect of: “[Insert operator’s name] application has beenassessed and is found to have satisfied the applicable legislative requirements.” 453

While there was an obvious lack of resources and technically qualified personnel at the DA’s office tomake important offshore permit decisions, the training and qualifications of NOPSA staff should also be

called into question. NOPSA was responsible for administering the Montara Wellhead Platform SafetyCase and the Atlas Drilling Rig Safety Case while drilling at the Montara Wellhead Platform. Testimony

446 Commission of Inquiry Transcript, April 13, 2010, p. 1961447 Commission of Inquiry Transcripts, April 14, 2010, p. 2168448 Commission of Inquiry Transcripts, April 14, 2010, p. 2171 449 Commission of Inquiry Transcripts, April 14, 2010, p. 2173450 Commission of Inquiry Transcript, April 13, 2010, p. 1960451 Commission of Inquiry Transcript, April 13, 2010, p. 1967452 Commission of Inquiry Transcript, April 13, 2010, p. 1963453 Commission of Inquiry Transcript, April 14, 2010, p. 2205



and the NOPSA investigation revealed that NOPSA did not coordinate with the other agencies that haveover-lapping jurisdiction on safety issues, nor does it appear that NOPSA had sufficiently trained andqualified staff that understood the significant risks associated with delayed topside installation, batchdrilling and long-term suspended wells.

The NOPSA incident investigation (interviews), completed in the fall of 2009, revealed NOPSA staff lack technical understanding of offshore oil and gas well operations, as evidenced by the request for witnessesto explain some elementary petroleum engineering principles. 454

All governments face challenges in hiring and retaining qualified personnel in regulatorypositions. In order to hire and retain qualified personnel government agencies need to offer salaryand benefit packages commensurate with those offered by oil and gas companies and theircontractors.

60. WWF-Harvey Report Final Draft 6 May 2010

Documents

Transcript of 60. WWF-Harvey Report Final Draft 6 May 2010