Coal seam gas well head safety program final report · Coal Seam Gas Well Head Safety Program Final...

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Coal Seam Gas Well Head Safety Program

Final Report

April 2011

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This report was prepared for use by the Safety and Health Division, Department of

Employment, Economic Development and Innovation. This report may not be reproduced in

any way, or any information contained within this report used in any way, without the prior

written approval of the Commissioner for Mine Safety and Health

APPROVED FOR RELEASE:

Date: 28 April 2011

Stephen Matheson

Chief Inspector, Petroleum and Gas

This report was prepared for use by the Safety and Health Division, Department of

Employment, Economic Development and Innovation. This report may not be reproduced in

any way, or any information contained within this report used in any way, without the prior

written approval of the Commissioner for Mine Safety and Health

.

© The State of Queensland, Department of Employment, Economic Development and Innovation, 2010.

Except as permitted by the Copyright Act 1968, no part of the work may in any form or by any electronic, mechanical, photocopying, recording, or any other means be reproduced, stored in a retrieval system or be broadcast or transmitted without the prior written permission of the Department of Employment, Economic Development and Innovation. The information contained herein is subject to change without notice. The copyright owner shall not be liable for technical or other errors or omissions contained herein. The reader/user accepts all risks and responsibility for losses, damages, costs and other consequences resulting directly or indirectly from using this information.

Final Report on the Coal Seam Gas Well Head Safety Program April 2011

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Contents

Executive Summary ………………………………………………………… 4

Abbreviations/glossary ……………………………………………………. 6

Explanatory terms…………………………………………………………… 6

1 Introduction ……………………………………………………………..... 8

2 Background ………………………………………………………………. 8

What is coal seam methane? ............................................................................................ 8

Well types.......................................................................................................................... 8

Well construction standards............................................................................................... 9

Methane properties and safty issues ............................................................................... 11

Safety management regime............................................................................................. 12

3 Compliance Directions 13

3.1 Background ............................................................................................................... 13

3.2 Response process to compliance directions .............................................................. 15

4 Summary of remediation work ……………...………………………. 16

4.1 Well inspection methodology and risk........................................................................ 16

4.2 Well summary inspection and leak details ................................................................. 17

4.3 Summary of remedial action undertaken ................................................................... 18

4.4 Overview of rectification work by required action ....................................................... 18

5 Petroleum and Gas Inspectorate Independent verification activities ………………………………………………………………… 27

6 Systemic safety improvement – Code of Practice ………….……. 29

7 Future action ……………………………………………………………………………. 29

8 Conclusions ………………………………………………………………………….….. 30

APPENDIX I - Summary of category 1 and 2 leaks …………………. 32

TABLES Table 1 Summary of Compliance Directions issued........................................................ 13

Table 2 Summary of reported leaks................................................................................ 17

Table 3 Multi-gas detector specifications ........................................................................ 22

Table 4 Combustible gas leak detector specifications..................................................... 22

FIGURES Figure 1 Surface casing.................................................................................................. 13

Figure 2 Typical CSG well site equipment ...................................................................... 10

Figure 3 Typical well head equipment ........................................................................... 11

Figure 4 Methane in air properties .................................................................................. 12


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Executive Summary

The well head safety program was instigated to investigate concerns relating to potential leaking coal seam gas (CSG) wells in the Tara rural residential estates. Initial investigations were undertaken by the Petroleum and Gas Inspectorate (P&G Inspectorate), which identified some gas leaks from wells and well related equipment. The P&G Inspectorate subsequently issued compliance directions to the Queensland Gas Company (QGC) to investigate and remediate the leaks. As a precautionary measure, compliance directions were subsequently issued to all active coal seam gas explorers and producers in Queensland to undertake similar inspections and remedial action where necessary.

The very nature of the CSG well environment, including the lighter than air nature of methane, the isolation of the well sites and their rural location, signage of the well sites and requirements for no ignition sources adjacent to the well provide significant controls of the risk of gas ignition.

Nevertheless and not withstanding these basic natural controls, the proactive approach of the P&G Inspectorate to issue the compliance directions and the substantive compliance from the industry has even further reduced the risk of an incident relating to gas leaks from completed CSG wells.

The program involved inspections of over 2719 wells and identified leaks relating to the well casing, the well head and related well head equipment.

Only five leaks were reported at a level over the lower flammable limit (LFL) where a flammable environment exists. Action was promptly taken to fix these five wells to secure the safety of the workers and the community. A further 29 leaks were identified below the LFL, but above a level where best practice dictates that action should be taken. These leaks have also been repaired.

The vast majority of other identified leaks were at very low levels only detectable by sensitive equipment immediately adjacent to the well and well equipment. These leaks cannot be detected once the detector is withdrawn some 300mm from the leak site. These types of leaks in an external environment represent negligible or no risk to the community and are monitored and actioned as required as part of the ongoing safety management plan that the companies are obligated to have under Queensland legislation.

As part of the well head program, security and signage at sites has been improved, greater focus has been undertaken on well head design and to ensure asset integrity is well managed.

The Department also undertook its own gas sampling and ambient air sampling to verify that there are no volatile organic compounds or toxic compounds present. The coal seam gas is typically more than 98% methane and at the well head is a clean non-toxic fuel; widely and safely used in the community.

To ensure compliance with the well head program, the P&G Inspectorate has reviewed company action plans and submissions and undertaken verification inspections. Extensions of the time required to complete the work was granted to some companies in cases where there was a legitimate and reasonable request for further time and where the delay did not compromise safety outcomes.


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As part of a verification of the company work over 230 wells have been independently inspected by the P&G Inspectorate to date. These verification inspections will continue to be undertaken now that access to well sites is possible after the land has dried out from recent flooding.

The program has also identified the need for a consistent approach to the inspection, testing and reporting of leaks. There were significant differences between the companies’ leak testing methodologies, such that company results could not be directly compared. To resolve this, the P&G Inspectorate led the development of a Code of Practice for inspecting, testing and reporting well head leaks. The Code has been called up under the Petroleum and Gas (Production and Safety) Regulation 2004 as of 15 April 2011 and will provide a consistent approach across the industry and ensure the required standard is achieved.

The P&G Inspectorate will continue the inspection and audit program, and undertake inspections of well head facilities along with an ongoing review of company practice as part of its normal compliance program to ensure that safety standards of the highest level are maintained and a culture of continuous improvement is encouraged.


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Abbreviations/glossary

APPEA Australian Petroleum Production and Exploration Association

CD Petroleum and Gas Inspectorate Compliance Direction

CSG Coal seam gas

ISO International Organisation for Standardisation

LFL The lower flammable limit

P&G Act Petroleum and Safety (Production and Safety) Act 2004

P&G Inspectorate Petroleum and Gas Inspectorate

PPM Parts Per Million

VOC’s Volatile organic compounds

Explanatory terms

Bull Plug A threaded nipple with a rounded end used to seal off open ends on pipe work, fittings and valves.

CSG Coal seam gas is mostly methane in composition and insitu; is typically attached to the coal along its natural fractures and cleats. This gas is released when pressure on the coal seam is reduced, usually by removal of water from the seam.

Category 1 Leak A leak measured at over 100% LFL.

Category 2 Leak A leak measured between 100%LFL and 10% LFL.

Christmas Tree An assembly of valves, spools, pressure gauges and chokes fitted to the wellhead of a completed well to control production.

Compliance Direction A direction issued by a Petroleum and Gas Inspector or authorised officer under the P&G Act to a person or company to take steps reasonably necessary to remedy a non-compliance or avoid the likely contravention of the P&G Act.

Exploration Well A well drilled to investigate the likelihood for future gas production.

Flange A mechanical joint bolted between sections of piping or well head sections. A special type connection in which a metal ring (resting in a groove in the flange) serves as a pressure seal between the two flanges.

Flowing gas well A well which produces gas without any means of artificial extraction.

Hazardous Zone Area An area where dangerous quantities and concentrations of flammable gas or vapour may arise. Protective measures are to be applied in order to reduce the risk of explosion.

ISO - 10423:2004 An international standard called up in the Petroleum and Gas (Production and Safety) Regulation 2004 (P&G Regulation) titled 'Petroleum and natural gas industries; drilling and production equipment – well head sections'


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LFL The Lower flammable limit (LFL) of a combustible gas describes the smallest amount of the gas that supports a self-propagating flame when mixed with air and ignited.

Risk The likelihood of damage, personal injury or loss or other negative occurrence caused by external or internal actions.

Risk assessment A component of a risk management system consisting of the identification of all possible negative external and internal conditions, events, or situations and establishment of control measures.

Shut-in Relates to a well where the flow of gas to the surface is stopped by closing the choke valves on the well head.

Stuffing box A conventional stuffing box is a well head device used to provide an axial seal around a rod string driving the down hole pump.

Surface casing Pipe used to structurally secure a well, provide blow-out protection, to seal off water/hydrocarbon sands, and prevent loss of circulation; seal off water sands, weak formations and/or lost circulation zones. In some cases surface and intermediate casing requirements are provided by the same string.

Production well A constructed well with a combination of control valves that extracts gas from below ground and is connected to pipes.

Production casing A casing string that is set across the gas reservoir interval and within which the primary completion components are installed.

Well head The top section or base of the above ground well head equipment of the well.

Well head equipment Assembled sections and valves above the ground including Christmas tree and associated separation equipment.

UFL The Upper Flammable Limit of a combustible gas describes the highest concentration (percent) of gas or vapour in air capable of producing a flash of fire in the presence of an ignition source.


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1

2

Introduction

This report provides a summary of the outcomes of the coal seam gas well head safety program announced by the Minister for Mines and Energy, the Honorable Stephen Robertson MP on 17 May 2010. The purpose of the report is to summarise the outcomes from the program. The report includes an overview of how industry has addressed each of the required action items and a summary of associated work including the Department of Employment, Economic Development and Innovation’s (DEEDI’s) P&G Inspectorate’s ongoing well head inspection and testing program.

The well head safety program comprised of:

1. Inspections, leak testing, evaluation, classification, reporting, leak remediation and other actions arising from compliance directions issued to all coal seam gas producers in May 2010;

2. A request to industry to develop a robust and consistent approach to well head inspection and reporting; and

3. Ongoing inspection and monitoring by the P&G Inspectorate.

Background

What is coal seam methane?

The coal seam gas industry began in earnest in Queensland with exploration in the Bowen Basin in the 1990s. Exploration increased rapidly over the next 20 years, which saw explorers evolving into producers. First production occurred in 1999 and there are now four major CSG players. All are based around multi-national gas companies Arrow/Shell; BG/QGC; Santos/Petronas and Origin/Conoco Phillips). These companies are working towards supplying an LNG export business requiring large volumes of coal seam gas to be produced from the Surat and Bowen Basins. A number of smaller explorers and producers are also present such as AGL, Bow Energy, Blue Energy, Icon Energy, Westside Corporation and Molopo.

Coal seam gas (CSG) also called coal bed methane, is mostly methane in composition and insitu is typically attached to the coal along its natural fractures and cleats. This gas is released when pressure on the coal seam is reduced, usually by removal of water from the seam.

Methane (CH4) is a hydrocarbon gas that is lighter than air and flammable in certain methane/air mixture concentrations (see safety levels of methane section on page 11&12. As well as being produced from coal seam seams, it is found in sandstone and shale.. Methane is also produced naturally from animals and the decay of animal and plant waste.

Well types

There are three phases of CSG operations: exploration, appraisal (pilot testing), and production. The wells vary in type from exploration wells, production wells connected to gathering systems, production wells shut-in and not connected to gathering systems, and ”plugged and abandoned” wells. Generally only production wells provide any potential for leaking gas as the well has been “completed” for production. In some (shut-in) wells, the head of water within the well is static and can reach equilibrium with the surrounding geological formation pressures. This in effect contains the gas in the well.


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The exploration phase investigates potential locations for gas production wells. This may include seismic surveys and the drilling of wells. If gas is found and an area considered as having potential for development, an appraisal well may be drilled. A pilot test is essentially a small-scale production trial, to gather data on the formation pressure, and water and gas volumes. If pilot testing indicates that commercial quantities of gas can be produced, full-scale production may commence. Production wells are generally spaced at 600m–1200m or more typically on a grid across the gas field.

In the Surat Basin, production wells to date have typically been vertical wells that intersect and produce from one or more coal seams. In the Bowen Basin surface to in seam wells have been commonly used often in a chevron pattern where two surface to in seam wells are drilled to intersect a vertical production well. This is a method of increasing the surface area of the coal seam exposed to the well to increase production. Production techniques vary according to the geology, depth and gas levels and a technique effective in one area may not be effective in another.

Well construction standards

CSG well heads are designed and constructed to international standards where applicable. Under the Petroleum and Gas (Production and Safety) Regulation 2004 (P&G Regulation), the relevant standard is: ISO 10423:2009 ‘Petroleum and natural gas industries - Drilling and production equipment - Wellhead and Christmas tree equipment’, based on API 6A specification using proven construction techniques and equipment. Other ISO standards such as ISO 10405 ‘Petroleum and natural gas industries – Casing and tubing’ 2006 are also called up in Schedule 1 of the P&G Regulation.

As the Petroleum and Gas Legislation is risk based, other standards may also be used and the worldwide American Petroleum Institute (API) series of standards are generally considered as good practice.

CSG wells are designed to ensure that wells are isolated from overlying geological strata, including overlying aquifers and to contain any produced gas with the casing and production tubing. It is in the industries interest to ensure well integrity, as leaking wells represent lost income and defeat the purpose of maximising gas production.

The facilities are pressure tested prior to commissioning to verify their integrity and CSG operators conduct routine monitoring to ensure ongoing safe operation of these facilities.

Once drilled and completed, the risk of actual leaks (and in particular an uncontrolled high volume leak from the well itself), is considered very low due to the well construction and design standards used for the wells. The risk of explosions from fugitive or very low level leaks is considered minimal as any gas release will quickly disperse in the air with CSG/methane being lighter than air. In addition the well heads and immediate hazardous zones are designed free of ignition sources.


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Figure 1 displays a typical well comprised of a large outer or surface casing, which is cemented into position against the surrounding earth formations. Suspended inside the surface casing is the much smaller production tubing which allows the production water and gases to come to the surface.

Figure 1 – Surface casing

Figure 2 displays how the surface well head equipment connects the production tubing and casing to a gathering pipeline or to surface gas separation equipment. The well head is a device that attaches to the casing as the casing protrudes above the ground. Production tubing is suspended inside the well casing and the flow of gas to surface can be controlled via a system of valves at the surface.

Figure 2 - Typical CSG well site equipment


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Figure 3 displays a typical well head assembly connected to casing. The well head consists of a combination of valves and piping used to extract gas from the well and separate water so gas can be processed for compression and dehydration. During the initial stages, some wells require to be pumped using mechanical head drives to extract the water and gas from the well (head drive is connected to top of well).

Figure 3 - Typical well head equipment

Methane properties and safety issues

CSG consists mostly of methane, which, like other forms of natural gas is used as a fuel in heaters, stoves and hot water systems in homes and businesses. Methane is non-toxic and is only flammable when the gas concentration is between 5 and 15 per cent of the total gas/air mixture. CSG is lighter than air, will rise naturally and quickly dilute and dissipate into the air. In addition to its application in domestic and business environments, natural gas is safely used in many other areas including transport fuels and as feedstock or fuel for industrial plants and power generation.

For CSG to form a flammable environment it must reach a concentration of between 5% and 15% of gas in air. The lower flammable limit (LFL) of a combustible gas describes the smallest amount of the gas that supports a self-propagating flame when mixed with air and ignited. In gas-detection systems, the amount of gas present is specified as a percentage (%) LFL. Zero percent (0%) LFL denotes an atmosphere that is free from a combustible gas. One hundred percent (100%) LFL denotes an atmosphere in which the gas concentration is at its lower flammable limit. In the case of methane this would mean a concentration of 5% in air (see Figure 4).


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Non – flammable range Flammability Non – flammable range (i.e. too little methane) Range (i.e. too much methane)

% Methane in air

0% < 5.0% > 15% 100% 5% 15%

0.05 0.5 1.0 5 15

LFL (%) 1 10 20 100 UFL#

ppm 500 5000 10 000 > 50 000 < 150 000 > 150 000 – 1 000 000

Figure 4 - Methane in air properties # UFL = upper flammable limit

Safety management regime

The main purpose of the P&G Act is to facilitate and regulate the carrying out of responsible petroleum activities and the development of a safe, efficient and viable petroleum and fuel gas industry.

Safety of coal seam gas exploration and production, gas pipelines and gas processing plants is regulated under the outcome, performance based legislation that requires robust safety management systems to be developed, implemented and regularly audited. All activities are subject to risk assessment and adequate controls are required to be in place to manage risk including supervision and training of staff.

In developing these safety management plans, companies undertake a risk based assessment process that identifies all potential hazards and consequences associated with the safe operation of gas wells. Appropriate strategies and control measures are then put in place to reduce the level of residual risk to workers and the community to as low as reasonably practical.

Industry compliance against this robust framework is regulated by the Petroleum and Gas Inspectorate (P&G Inspectorate) of the Department of Employment Economic Development and Innovation (DEEDI). In the case of major hazard facilities (MHF’s) (such as future LNG plants), compliance is regulated by the Hazardous Industries Chemicals Branch (HICB) of Workplace Health and Safety.

The P&G Inspectorate undertakes inspections, audits and investigations to ensure compliance against the legislation. Companies are also obligated to provide annual safety reports which detail compliance The P&G Inspectorate has a range of compliance or enforcements tools including advice, safety management plan (SMP) validation notices, compliance directions and dangerous situation notices. Ultimately, there are offence provisions under the Legislation and companies can be prosecuted and fined.


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3 Compliance Directions

3.1 Background

Concerns raised by some rural residential estate owners in the Tara region regarding potential leaks from gas wells and well head equipment and the toxicity of the gases resulted in the P&G Inspectorate initiating an investigation. The wells subject to the complaints were located on petroleum tenures operated by the Queensland Gas Company (QGC). Preliminary investigations by the P&G Inspectorate led to QGC being issued two compliance directions (CD’s) in February and April 2010 requiring them to undertake specific actions including necessary remediating action.

The findings of those investigations, subsequently led to compliance directions being issued by the P&G Inspectorate under the P&G Act to all CSG producers. Compliance directions were issued on 14 –17 May 2010 to eleven CSG companies: Arrow Energy, AGL, Bow Energy, Blue Energy, Comet Ridge, Icon Energy, Westside Corporation, Molopo, Santos, Origin Energy and Anglo Coal. Note: Anglo Coal. (Dawson Seam Gas assets are now owned and operated by Westside Corporation Ltd and Molopo Energy Limited).

Table 1 Summary of Compliance Directions issued

CD Number Company Date of issue Issued to

1674 QGC 19/2/2010 Operator 1741 QGC 30/4/2010 Operator 1771 Santos 14/5/2010 Operator 1772 Comet Ridge 14/5/2010 Operator 1773 Arrow energy 14/5/2010 Operator 1774 AGL 14/5/2010 Operator 1775 Bow energy 14/5/2010 Operator 1776 Blue energy 14/5/2010 Operator 1777 Icon energy 15/5/2010 Manager 1778 Westside Corporation 15/5/2010 Operator 1779 Molopo 15/5/2010 Operator 1780 Origin 15/5/2010 Operator

This was undertaken to provide for a whole of industry check to enable a baseline of information across all coal seam gas wells across the state. The compliance directions required each CSG company to undertake a series of actions, to be completed by 11 June 2010 and these were: 1. Carry out a risk assessment of emissions from potential leakage sources at well sites

and establish categories of emission which will determine the necessary remedial action. Dependent on concentration of gas measured at the source of emission, actions are likely to include, but not be limited to: “immediate repair”, “repair as soon as reasonably practicable”, “establish exclusion zone of ‘x’ metres”, “monitor level of emission for ‘y’ duration”. The exact categories will be established during the risk assessment. The risk assessment team will be chaired by an independent party.

2. All pressurised wells must be inspected as soon as practicable and leak tested at all joints, valves, threads and other potential leak points using a portable calibrated ppm gas detector to detect any leak.


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3. The organisation must take all necessary remedial action (in accordance with risk assessment categories identified in Item 1) to address any leaks identified as soon as practicable.

4. The security and isolation of access of all well heads must be reviewed as part of the risk assessment with a view to limiting access to any potential hazardous zone around the well and well head equipment.

5. The organisation must expeditiously acquire ppm gas detectors for its field operators to enable appropriate inspection of wells to determine any level of gas leak on a regular basis.

6. Over and above any routine inspection of wells, a regular (as determined in the risk assessment) survey of wells should include checks with a ppm gas detector.

7. The appropriate action level for reporting to the Inspectorate will be established in the above risk assessment, and will be agreed with the Inspectorate. Once agreed all leaks required to be reported must be reported in the agreed manner to the Petroleum and Gas Inspectorate (via the [email protected] email or 24/7 emergency numbers) including the location and size of leak.

8. All well head equipment must comply with requirements of relevant standards in the Petroleum and Gas (Production and Safety) Regulation 2004 (e.g. ISO 10423 based on API 6A specification). Any well heads that do not comply with the relevant standard should be identified to the Inspectorate and action taken to comply with the regulation.

9. All well head equipment assemblies must be inspected and reviewed to ensure their long term integrity is being maintained.

10. Any open ended valves or fittings must be fitted with an appropriate sealing plug.

11. Undertake representative analysis for each coal seam gas field (including provision of details of any existing analyses) to determine if any volatile organic compounds (VOC’s) and heavy metals occur in the gas stream at both the well head and the gas plant. Representative sampling of the ambient air adjacent to a well should be undertaken as well as from and around wells preferably at any site where there are known fugitive emissions (gas leaks).

12. Undertake representative analysis for each coal seam gas field (including provision of details of any existing analyses) of exhaust emissions from representative well head gas fired engines.

13. Reports of the analysis undertaken as per Items 11 and 12 must be provided to the Chief Inspector Petroleum and Gas, with a view to demonstrating that the organisation’s operating plant workers, gas users and the general public are not exposed to an unacceptable level of health risk.

14. An action plan must be developed to outline and implement the actions required from the review in Items 1 and 3, and must be submitted to the Chief Inspector Petroleum and Gas Inspectorate.


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15. Provide a weekly report to the Chief Inspector P&G on the progress of each action as required above, until all remedial actions have been completed. This is to include identification of the number and location of gas leaks that have been found and what action has been taken with respect to addressing those leaks.

3.2 Response process to compliance directions

Companies in general demonstrated a high level of compliance to the compliance directions issued. A range of information was provided about existing compliance where they had already complied or further actions taken to achieve compliance with the direction. In numerous cases, the majority of the action items had been voluntarily completed prior to receiving the compliance direction, as part of the companies’ normal business practices, and safety management systems.

The P&G Inspectorate permitted some companies extensions to the time required to complete the work. This is standard approach where there is a legitimate or reasonable request for further time and when the delay does not compromise safety outcomes.

In one case, Molopo Energy formally requested (and was granted) a time extension until 31 October 2010. This was on the basis that they were unable to gain appropriate permission and subsequent access to some of the joint venture leases operated by Anglo Coal until the final acquisition of all the assets was finalised.

QGC complied with the original compliance direction (CD1741) in relation to all well heads located on their Kenya CSG leases in the Tara block estates.

However, QGC reported that they had not inspected every well on its other CSG fields in the Surat and Bowen Basins. This was not part of the original CD given to QGC. QGC then agreed to extend the work to all their wells throughout Queensland, but additional time was required as a third party contractor was engaged to complete these outstanding well inspections by 30 September 2010.

The task to manage the detailed information provided by the companies was both ongoing and complex. Data had to be collected, verified, analysed and compared by the P&G Inspectorate. Throughout the well head program regular updates and meetings were provided or undertaken where necessary so the P&G Inspectorate could ensure progress was being made. Where insufficient data or information was supplied, the respective companies were requested by the Chief Inspector to address these gaps and to provide the required information. The P&G Inspectorate permitted the companies reasonable agreed periods to undertake the additional work; and to provide the additional information was determined. Where necessary, specific issues identified by the P&G Inspectorate (through its inspection and testing program) were addressed.

The P&G Inspectorate has reviewed all submissions and information provided against the 2719 wells and examined these in detail. Follow up action has been undertaken where required. Two companies have on-going requirements concerning some specific actions.


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4 Summary of remediation work

4.1 Well inspection methodology and risk

At the time of the commencement of the well head program, there was no recognised International or Australian Standard for leak testing of the wells. As a result, all companies applied their own methodology to investigate and remediate the leaks based on the relevant company’s best practice at the time. As the program advanced, it was identified that there were variances among the companies regarding the methodology used to detect and record leaks.

This included differences in equipment, personnel used (i.e. in-house or contractor) and detection source distances. The majority of companies utilised their own staff to undertake the leak inspection, testing and collecting of data. Three companies contracted specialist infield consultants to carry out the leakage survey on their behalf.

QGC utilised a third party contractor and initially they adopted an approach of placing their gas detector sensor probes hard against the well head connections while surveying for leaks. However, the majority of the remaining companies undertook a different survey system, which recorded readings at predetermined distances off the well head for example distances of 150 to 300mm from the leak source in an open air environment above the ground.

Weather conditions such as the wind speed and direction can also affect leak detection readings on any given day when using portable gas detection equipment. Regardless of the methodology used, the inspections and testing indicated that very few leaks were found to be within a range that represented any risk.

Given the variation in conditions and methodologies, the same leak could be reported at different levels. In addition, the classification of leaks based on their methane LFL readings varied significantly between companies. As a result, it is difficult to compare leak numbers across companies.

Leaks are typically classified in accordance with risk. Risk of ignition relates to the concentration of methane in air. Any leak over the LFL (see page 11 for definition), poses an immediate risk and must be controlled. Initial controls may include isolation of the site and exclusion of any ignition sources. This would be followed by repair. Identifying and actioning all leaks that are from below 100% LFL to a deemed safety level such as 20% or 10% of the LFL ensures best practice safety margins. Other minor ppm leaks pose minimal or no risk and can be monitored and actioned as required as part of the ongoing safety management plan that the companies are obligated to have under Queensland legislation.

Some of the reported leaks erroneously included gas emissions from pressure relief valves as detectable leaks. A pressure relief valve is designed to release excess pressure of gas intermittently to the atmosphere and forms an essential part of the overall safety design of the system. It is not useful or appropriate to include these as leaks as they are controlled and planned emissions.


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4.2 Well summary inspection and leak details

Information provided by the companies at the time of issuing the compliance directions in May 2010 identified that there were some 2719 completed coal seam gas wells throughout Queensland.

Wells vary in type from production wells connected to gathering systems, production wells shut-in and not connected to gathering systems, exploration wells, and “plugged and abandoned” wells.

From the data provided, 2719 wells were completed at the time of the CD’s being issued. At the time of the original expiry date of the 11 June 2011, the majority of the wells were inspected leak tested and remediated where required by early August 2010. Aside from 36 wells identified by QGC as outstanding, all the remaining wells were inspected by 31 October 2010. Further compliance action is pending in regard to the responsiveness of inspecting and actioning issues on these wells.

Of the 2719 wells inspected, only five leaks were identified and reported to the P&G Inspectorate at a level of over the LFL (described as a category 1 leak in this report). Action was taken to immediately control and repair these leaks. There were also 29 leaks reported in the range from below 100% LFL to as little as 10% of the LFL (described as a class 2 leak in this report). As discussed earlier, leaks in this second category while posing no immediate risk, are considered from best safety practice as being at a level where some remediation action should be undertaken. All 29 leaks have been repaired.

The leak numbers listed above are of all individual leak points and not wells; as there could be more than one leak point at a well site. Companies also identified and reported numerous leaks at levels below 10% of the LFL’s (with most below 1% LFL). These pose no risk to the public. This category of leaks will only be detectable immediately adjacent to the leak site.

Table 2 Summary of reported leaks

Company Total wells Category 1 (Leaks over 100%

LFL)

Category 2 (Leaks between 10% LFL and 100% LFL))

AGL 11 0 0 Anglo/Dawson 153 0 0 Arrow Energy 895 0 3 Bow energy 43 0 1 Blue energy 33 0 0 Comet Ridge 4 0 0 Origin energy 270 0 3

QGC 705 5 19 Santos 538 0 1

Westside 23 0 2 Molopo 25 0 0

Icon Energy 17 0 0 TOTAL 2717 5 29


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The differences in methodology used by companies’ means that reporting these minor leaks is misleading. For example, it is known that QGC (via third party contractors) used a methodology of detection immediately adjacent to the well equipment for about 2/3 of their inspections. This is not an appropriate method because every minute leak will potentially provide a >100% LFL reading. This is largely responsible for the elevated number of Class 3 leaks identified by QGC. Because the leaks have not been appropriately measured, and are therefore incorrectly overstated despite presenting minimal or no risk, these leak numbers are not reported in this final report. As a precaution, QGC have been directed to re-survey these wells in accordance with an agreed methodology (the new “Code of Practice”). The results of this work will be available in May 2011.

4.3 Summary of remedial action undertaken

Details of the five leaks identified in category 1 and the 29 leaks in category 2 are provided in Appendix 1. Further detail on the types of leaks found is reported against action 3 on page 19.

All the category 1 and 2 leaks listed in the tables have been repaired. The well head safety program was focussed on a review of wells at the time of the program. Companies continue to inspect wells drilled and completed since the program commenced and also undertake an ongoing inspection program of existing wells. If leaks are identified either by company inspection or by the P&G Inspectorate, these are remediated as required.

As a result of the well head safety program all companies have now undertaken a full review of their risk assessments in regard to well heads and well equipment. Every well head has been subjected to a new risk assessment based on its location, land access and individuals having access on to each lease. Improved barrier fencing has also now been installed around every well head identified as being at risk because of these individual risk assessments.

4.4 Overview of rectification work by required action

A summary of the company’s’ responses against each of the required actions in the compliance directions (listed in 2.1 above) are provided below:

Action 1: Carry out a risk assessment of emissions from potential leakage sources at well sites and establish categories of emission which will determine the necessary remedial action. Dependent on concentration of gas measured at the source of emission, actions are likely to include, but not be limited to: “immediate repair”, “repair as soon as reasonably practicable”, “establish exclusion zone of ‘x’ metres”, and “monitor level of emission at ‘y’ duration”. The exact categories will be established during the risk assessment. The risk assessment team will be chaired by an independent party.

From the submissions supplied to the P&G Inspectorate, it was established that the majority of the companies had already completed their own risk assessments in regard to gas leakage as part of their ongoing obligations under the P&G Act prior to the P&G Inspectorate issuing the compliance directions.

The results of these assessments varied between respective companies due to the status of the well completion (i.e. exploration, development and production wells) and of activities currently occurring at each well site. A range of measurement distances from the leak


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source were used by companies, from immediately adjacent to the source to 300mm from the source.

As a result of the compliance direction, major operators have developed specific methodologies for classifying and remediating leaks. It was evident from this information that there were a variety of approaches being used. This included a variety of measurement distances and also classification systems and reporting systems.

This prompted the P&G Inspectorate to develop an industry-wide standardised approach to well head leak testing (see action 6). The majority of the major CSG companies have been involved in the development of a Code of Practice for leak identification and reporting. This will result in a common categorisation of leaks and how they are to be reported. It also means that industry wide as well as individual company performance can be more closely and consistently scrutinised. This is a major outcome from the well head safety program.

Action 2: All pressurised wells must be inspected as soon as practicable and leak tested at all joints, valves, threads and other potential leak points using a portable calibrated ppm gas detector to detect any leak.

A completion deadline of 11 June 2010 was initially set for all the work required in the compliance directions. By that time, the majority of inspections had been undertaken. However, due to the very significant number of wells involved, a combination of inclement weather and shortages of specialist technical field staff servicing the CSG industry, time extensions were requested by Arrow Energy, QGC and Westside.

These extensions were granted by the Chief Inspector to allow these companies sufficient time to complete their well head gas sampling and testing programs. By the end of October 2010, all inspections and testing requested under the compliance directions was completed other than 36 wells identified by QGC as outstanding. Further compliance action is pending in regards to the delayed inspection of these wells.

Companies either used their own staff or specialised contractors to undertake this work. Testing was undertaken at all parts of the well and associated equipment. Leaks at any part were recorded and reported. The results of the testing are summarised above in Table 2 and details of category 1 and 2 leaks provided in Appendix 1.

Action 3: The organisation must take all necessary remedial action (in accordance with risk assessment categories identified in Item 1) to address any leaks identified as soon as practicable.

Analysis of the information provided by the companies identified that the majority of the leaks were emanating from threaded connections on the well heads and related well head equipment. These included:

• Incomplete thread tensioning on pipe work and fittings;

• Lack of sealant tape used on threaded connections;

• Blind plugs not fully tightened;

• Isolation or control valves not plugged off with valves passing gas;

• Flanged connection not fully tensioned allowing gas to pass; and

• Small stainless steel pipe work to pressure gauges not fully tensioned.


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The majority of these leaks were easily repaired soon after being identified by field operators. In many cases, it involved the removal of the leaking fitting, applying fit-for-purpose thread tape to the threaded section, and re-tensioning.

Other leaks were identified as emanating from the ground around the wells or from the well casing itself. The majority of these leaks require a work over rig to re-open the well and affect the necessary repairs. The requirement for a work over rig, access and associated equipment all impact on the timeliness of the repairs. For pressurised wells this must be conducted in accordance with strict procedures and may involve replacement of casing fittings or re-cementing in the well.

All of the five category 1 (>100% LFL) leaks were reported to be sourced from the well head and associated equipment, in particular at the pump drive head stuffing box gland seals. There were no category 1 leaks sourced from the well casing or surrounding area.

The majority of the 29 category 2 leaks were sourced at glands, seals and threads to the well pumping and separation equipment of which a majority were rectified at the time of detection. The remaining category 2 leaks were rectified through planned maintenance and shutdown.

Less than a third of the category 2 leaks stemmed from the casing area and all have been rectified. Rectification of these leaks in some cases was delayed by flooding and limited access to sites due to road conditions and also the availability of the work over rigs.

One particular QGC well (Argyle 2#) was identified as having a reportable leak during the inspection program and was scheduled for repair. Because the leak was on the well head casing, the repair necessitated the use of a well completion rig to safely undertake the significant work required. Delays in completing this work were mostly due to poor weather and access conditions around the location of the well. A work over rig undertook a plug and abandonment procedure with initial success, but subsequent monitoring found small concentrations of gas being recorded leaking from around the outside of the surface casing. A second remediation attempt was scheduled to repair the leak however, again due to wet weather conditions at the well site the final repair could not be recommenced until late February 2011.

Following this work, Argyle 2# has been successfully plugged and abandoned. As a precautionary measure, QGC conducted gas monitoring on a daily basis of the surrounding area for two weeks after the work had been completed. The well site has now been completely rehabilitated and independently inspected by the P&G Inspectorate with no leaks found.

It should be noted that BG/QGC along with companies such as Dawson and Molopo have inherited or operate some legacy well equipment built before the various standards were called under P&G Act when the Act commenced 1 January 2005. QGC has undertaken to ensure all wells comply with required standards before any wells are made operational.

Action 4: The security and isolation of access of all well heads must be reviewed as part of the risk assessment with a view to limiting access to any potential hazardous zone around the well and well head equipment.

As part of their well head assessments, CSG companies have reviewed well site security of each well head. The assessments considered a range of factors that would impact on the type of well head isolation and barriers required. These factors included proximity to rural


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dwelling, rural areas, other fencing on the property and proximity of public road access to each well head. Some CSG companies have purchased the land on which they operate and as a result they have eliminated many of the public access aspects identified by the risk assessment process.

However, in some instances wells are located within eyesight of a public roadway. In accordance with the risk assessment, these sites require a higher level of site security.

CSG companies have introduced three types of security fencing around their well heads. These consist of the standard four-strand wire and star-picket style lease perimeter fencing and a lockable cattle gate around the lease. Where cattle are present within paddocks a second similar fence or hard metal cattle fence is placed around each well site to keep cattle away from the well and its well head equipment. Finally, if the risk assessment deems appropriate either a 1400 or 2400 mm high meshed lockable security style fence is installed in close proximity around identified high risk well sites. This final fence is generally placed at a specific distance from the well head dictated by hazardous zone requirements. This is meant as a final alert to field operatives and anyone else that they must not enter these areas without a proper work authority or work permit and to exclude all ignition sources.

Each company have advised that the main gate to every well site is sign posted with 24-hour emergency contact numbers for their respective companies along with warning signage in relation to the potential for flammable gas and restriction of ignition sources at every well site.

The well head program has resulted in a significant improvement in regard to these issues.

Action 5: The organisation must expeditiously acquire ppm gas detectors for its field operators to enable appropriate inspection of wells to determine any level of gas leak on a regular basis. and Action 6: Over and above any routine inspection of wells, a regular (as determined in the risk assessment) survey of wells should include checks with a ppm gas detector.

Action 5 was included as it was initially not known what detectors were being used nor the accuracy and sensitivity of this equipment. The program has provided this information and the “Code of Practice” (published on the DEEDI website) now sets the required accuracies and methodology for detection.

Multi-gas detectors

The majority of companies utilised multi-gas detectors for the inspection of their wells. These detectors are intrinsically safe (i.e. cannot cause ignition of flammable gases) and measure the concentration of multiple gases in air. Gases can include hydrogen sulphide (H2S), carbon monoxide (CO), oxygen (O2) and methane (CH4). They provide continuous visual confirmation of detector operation and a continuous LCD shows real-time gas concentrations. They are used worldwide in all gas applications and are well accepted in the industry.

Typical specifications for a multi-gas detector are shown in Table 3. Multi-gas detectors are usually set to ensure that an alarm will be activated at no more than 25 % of the LFL.


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Table 3 Multi-gas detector specifications

Gas Detected Measuring Range Resolution Alarm set points for all sensors are user adjustable. Set points are automatically displayed during instrument start up.

Alarms are generally visual and audible

H2S 0-100ppm 1ppm

CO 0-500ppm 1ppm

O2 0-30.0% 0.1%

CH4 0-100% LFL 0-5.0% v/v

1% 0.1%

Combustible gas leak detectors (photo-ionisation)

Combustible gas detectors are intrinsically safe and are designed to primarily detect the source of a combustible gas leak. They are generally hand held and include an extendable flexible probe with a photo ionization solid-state sensor. A number of LEDs can illuminate providing the user with a visual indication of the relative gas level, while a speaker produces a clicking sound, similar to a Geiger counter that rapidly increases as the gas concentration proportion increases (depending on the instrument’s gain setting)

Photo ionization detectors are highly sensitive and detect low gas concentrations down to parts per million.

Typical specification for a combustible gas leak detector is outlined in Table4.

Table 4 Combustible gas leak detector specifications

Response time 3 seconds to full scale

Sensitivity 20ppm (CH4)

Sensor Solid state

Gas indication Visual: LED’s (scaled) Audible: Variable speed ticking sound that increases upon concentrations detected

Adjustment Variable < 20ppm

Development of the “Code of Practice" has led to the conclusion that combustible gas leak detectors are not necessary in the routine inspection of well heads. Personal multigas detectors have sufficient accuracy to ensure leaks are measured to the necessary LFL levels. In addition, mandating combustible gas leak detectors could be counter productive as they require specific training to use and are not as robust as the multigas detectors.

This type of detector is better used for specialised integrity checks at plant rather than routine well head inspection by field operators.


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Action 7: The appropriate action level for reporting to the Inspectorate will be established in the above risk assessment, and will be agreed with the Inspectorate. Once agreed, all leaks are required to be reported in the agreed manner to the Inspectorate (via the [email protected] email or 24/7 emergency numbers) including the location and size of leak.

The well head program identified that a variety of methodologies were used to detect leaks and therefore reporting also widely varied.

The P&G Inspectorate initiated a working group to develop a “Coal Seam Gas Industry Code of Practice for well head emissions detection, classification and reporting requirements”. This provides for a consistent approach to the methodology used to identify, remediate and report leaks on wells and well head equipment.

The Code (details provided in section 6) provides a common methodology for testing wells and wellhead equipment. It also has a common “gas leak classification scheme” for actioning, remediating and reporting leaks to the P&G Inspectorate. This provides a common approach across industry for measures and dealing with these leaks.

A number of companies were initially utilising the main principles in the draft Code as they progressed through their testing program.

As of the 15 April 2011, the “Code of Practice” has been called up by the P&G Regulation and is a safety requirement as a preferred standard. Not complying with a safety requirement is an offense under the P&G Act.

Action 8: All well head equipment must comply with requirements of relevant standards in the Petroleum and Gas (Production and Safety) Regulation 2004 (e.g. ISO 10423 based on API 6A specification). Any well heads that do not comply with the relevant standard should be identified to the Inspectorate and action taken to comply with the regulation.

The majority of well head equipment used in Queensland is supplied by the Wood Group. The Wood Group is a major international supplier of well head equipment designed to meet the specified requirements of ISO 10423:2009 ‘Petroleum and natural gas industries Drilling and production equipment - well head and Christmas tree equipment’ that is based on American Pipeline Institute (API) 6A specification.

AGL, Bow Energy, Icon, Origin, Santos and Westside all reported that they utilise well head equipment compliant with the required standards.

Arrow Energy well heads are designed to API 11W specification. Arrow has certified that the API 11W specification is the structurally and dimensionally equivalent to the requirements of ISO 10423 standard. However, Arrow advised they had completed their risk assessment process and concluded that the only difference between the required standard and the standard used was that the API 11W designed equipment does not come supplied with a pressure test certificate from the equipment manufacturer at the time of purchase. Arrow management has advised infield testing similar to manufacturing pressure testing was carried out at the time of well completion.


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QGC also identified some well heads designed to API11W. None of these are operating wells. QGC will ensure all wells comply with required standards before any wells are made operational.

Dawson, Westside and Molopo identified that their wells were not all fully compliant with the standard. Many of these wells are drilled on a mining lease where the rights to extract the gas arise under the mining lease prior to the P&G Act (when the requirement for the ISO standard commenced) being introduced. The P&G Inspectorate is working with these companies to ensure they have a forward plan to provide for the necessary compliance.

In summary while the wells are not leaking at reportable levels, the companies are required to ensure compliance so that the long term integrity of the wells can be assured.

Action 9: All well head equipment assemblies must be inspected and reviewed to ensure their long-term integrity is being maintained.

The major CSG production companies now have in place specific asset integrity divisions within their respective companies. These divisions are responsible for scheduling and tracking of all maintenance and inspection programs and prioritising essential well repairs to prevent incidents.

Some companies have developed well integrity manuals that detail standard operating procedures in relation to well design and construction; maintenance; inspection and testing periods.

There are also inspection and testing checklists for infield staff. All infield staff are trained and must be assessed as competent to undertake specified work activities on their wells.

Under the existing safety management plan (SMP) requirements of the P&G Act, the CSG companies are required to develop and maintain a detailed maintenance register for each asset (well head) subject to audit by the P&G Inspectorate.

Under the Code of Practice formal integrity checks will be undertaken on 20% of wells every year along with the normal regular operational checking.

Action 10: Any open-ended valves or fittings must be fitted with an appropriate sealing plug.

As part of the well head safety program, the P&G Inspectorate identified a number of open-ended valves/flanges and fittings. Investigations revealed that it was common industry practice, for bull plugs to be tightened by hand, so they are easily removed for subsequent inspections. The P&G Inspectorate identified this work practice as an unacceptable safety risk.

As a result, companies undertook to identify these issues and implement a program for their rectification. CSG companies have greatly improved the work culture of their infield operators to ensure this becomes a routine work practice to identify and initiate immediate action. Verification inspections by the P&G Inspectorate after the CD’s were issued and actioned have shown substantial compliance in this area.


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Action 11: Undertake representative analysis for each coal seam gas field (including provision of details of any existing analyses) to determine if any volatile organic compounds (VOC’s) and heavy metals occur in the gas stream at both the well head and the gas plant. Representative sampling of the ambient air adjacent to a well should be undertaken as well as from and around wells preferably at any site where there are known fugitive emissions (gas leaks). and Action 131: Reports of the analyses undertaken as per Items 11 and 12 must be provided to the Chief Inspector, Petroleum and Gas, with a view to demonstrating that the organisation’s operating plant workers, gas users and the general public are not exposed to an acceptable level health risk.

AGL; Blue Energy; Comet Ridge and Icon Energy have all stated that they did not have any production wells at the time of the issue of the compliance directions as their respective operations had not progressed to the production phase and consequently it is acceptable for those companies to not meet this CD requirement (as no gas could be collected).

The remaining eight CSG companies provided gas analysis reports from NATA (National Association of Testing Authorities) accredited laboratories. The majority of these were undertaken as a direct result of the CD being issued. However, several gas analysis reports provided were undertaken by these companies during the exploration phase of their operations. These reports were considered acceptable.

Each company provided differing forms of gas analysis reports from their gas stream and ambient air sampling that were taken during the exploration phases of the activities. These reports indicated insignificant or no VOC’s or heavy metals within the gas. On average, the methane content of the gas was around 98-99.5% methane.

Note: the Department's Safety in Mines Testing and Research Station (Simtars) also independently undertook gas samples from gas production wells for analysis. These tests confirmed that these gas samples were 99% methane with small amounts of nitrogen, carbon dioxide, and ethane, normally found in natural gas, as well as a non-toxic amount of hydrogen sulphide, commonly found in coal seams. All levels were well within public health standards. The Simtars analysis report is available from the Department’s web page: www.dme.qld.gov.au/mines/test_results_from_tara_gas_samples.cfm .

Companies will be requested to continue to take samples on a regular basis and particularly as production from new fields occurs.

1 Action 13 is included here because it relates to the reporting of Action 11 as well as Action 12 over

page.


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www.dme.qld.gov.au/mines/test_results_from_tara_gas_samples.cfm

Action 12: Undertake representative analysis for each coal seam gas field (including provision of details of any existing analyses) of exhaust emissions from representative well head gas fired engines. and Action 132: Reports of the analyses undertaken as per Items 11 and 12 must be provided to the Chief Inspector, Petroleum and Gas, with a view to demonstrating that the organisation’s operating plant workers, gas users and the general public are not exposed to an unacceptable level of health risk.

Companies that operate conventional (gas fuelled) combustion engines at their well sites had undertaken some form of ambient air sampling. The remainder have opted to operate electrically driven well head (pumps etc.) equipment, which removes the whole issue of combustion exhaust emissions from the surrounding atmosphere. A number of companies had only exploration wells and so this action is not relevant as no gas has been produced.

Air pollutants may come from incorrectly tuned internal combustion engines. Engines are designed to incorporate sophisticated engine management systems that continually monitor air/fuel ratios to manufacturers specifications. CSG has been proven to be a cleaner and greener fuel.

Testing and sampling was typically undertaken by third party testing agencies such as AMDEL Consulting. Air samples were collected downwind of the engines exhaust. These samples were collected from the ambient air and later analysed by gas chromatography. The purpose was to identify if there were high levels of any substances that may pose a potential health risk. The results from these analyses indicate low levels of combustion products in air from samples taken from the surrounding atmosphere and these were below existing occupational exposure standards as set by the National Health and Medical Research Council.

Air pollution is generally categorised into ambient pollution (affecting a large number of people) and local pollution where the effects are limited to the area surrounding the source. No air testing indicated any significant levels of analysed substances that pose a health threat to infield workers or to the surrounding public.

Companies have advised that they are currently examining the best options for well pumping equipment and electrically powered engines are being considered as more viable long term options by some companies.

Action 14: An action plan must be developed to outline and implement the actions required from the review in Items 1 and 3, and must be submitted to the Chief Inspector, Petroleum and Gas Inspectorate.

In some cases, the company undertook all work immediately and no on-going action plan concerning the direction was needed. Action plans were provided by some companies who sought additional time or had on-going work to complete. In several cases, the P&G Inspectorate requested additional information in relation to the plans and was satisfied that no risk was attached to the extended work plan or that risks had been adequately managed.

2 Action 13 is also included here as it relates to the reporting of Action 12.


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5

Under the “Code of Practice” each company is now required to detail all identified and classified leaks in their annual safety report to the Chief Inspector and outline actions completed or scheduled for their repair.

Action 15: Provide a weekly report to the Chief Inspector, P&G Inspectorate on the progress of each action as required above, until all remedial actions have been completed. This is to include identification of the number and location of gas leaks that have been found and what action has been taken with respect to addressing those leaks.

Through-out the course of the well head safety program. the majority of the CSG companies provided weekly updates in differing forms to the Chief Inspector. Where weekly updates had not been provided to the P&G Inspectorate, individual companies were followed up and requested to submit any outstanding information. In some cases, weekly reports were not needed because a report detailing all completed actions had already been provided (e.g. Santos and Origin Energy).

Petroleum and Gas Inspectorate Independent verification activities

The P&G Act provides powers for Inspectors to conduct inspections to determine whether operators comply with the P&G Act and P&G Regulation. Since the issuing of the compliance directions, the P&G Inspectorate has undertaken a program of verification inspections to confirm the reported information was correct.

A total of 226 wells in the Bowen and Surat Basins have been inspected by the P&G Inspectorate to date, several of which have been inspected on more than one occasion. The quantity of inspections has been restricted due to the adverse weather conditions restricting access to sites.

The inspection of each well head consisted of a visual inspection of the overall site including the efficiency of security fencing, emergency contact information (signage), site access, compliance of materials and thorough a gas leak survey of the well head and associated plant using highly sensitive gas detection equipment.

Observations made during these inspections confirmed that appropriate fencing of some existing, unsecured sites was now completed with additional stockpiles of fencing materials ordered in readiness for all newly completed wells. The inspections identified that each CSG operator has conducted a site security risk assessment of each well and installed security fencing depending on the level of risk. These vary from star pickets and fence wire to 2.4 metre high fencing, depending on the location of the well. In addition, further consideration was allowed for cattle interference and vegetation management during each risk assessment.

On most occasions during these inspections, the Inspectors were accompanied by the CSG operator staff, who immediately noted for action any identified issues such as leaks, non-compliant installations and inadequate security. When Inspectors were not accompanied by the respective operators, identified leaks or other site issues were reported to the respective gas operators for rectification.


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Findings of the well inspections identified minor gas emission readings on well heads, however the majority of leaks were discovered on the well associated equipment such as the gas/water separators and gas pressure regulators. This type of equipment is generally installed during the initial stages of the well development and is later removed when the well flows freely. The vast majority of leaks were detected at parts per million (ppm) levels immediately adjacent to the source of the leak, such as a threaded connection, flange or mechanical seal (o-ring). However, withdrawing the detector to a distance of 150mm (6”) from the source failed to detect any gas readings. On other occasions, lower flammability (LFL) readings were detected at source and reduced to low PPM when withdrawn to 150mm. These results were consistent with company reported results and the leaks pose no level of risk, however each operator is required to monitor any readings to ensure these risks remain as low as reasonably practical.

Once these minor leaks were identified in most cases they were repaired either by re-tightening or by re-sealing threaded joint connections by the operating staff at the time of the inspection. For any substantial leaks identified, such as regulators venting, each operator was directed to action these immediately. For leaks that could not be addressed immediately, operators implemented controls to ensure the well integrity and provide a plan for the rectification at a later date. In one case, the P&G Inspectorate directed the operator to isolate the well as it could not be actioned immediately.

A comparison was conducted of the findings identified by the P&G Inspectorate and the results provided by the CSG operators in relation to the compliance direction requirements. Overall, the findings were found to be similar, however the Inspectors identified leaks on equipment not previously identified by the operators such as seals on the well head drives and venting of regulators. These findings are mainly due to failure of mechanical seals on moving equipment, similar to the engine of a vehicle and could occur at any time. Although these findings provide no element of risk, each operator has developed a well inspection and maintenance program to systematically identify leaks and action them accordingly.

The P&G Inspectorate also engaged a third party gas detection organisation (Heath Consulting) to provide an independent confirmation of the testing of some (ten) of the wells that were previously reported as category 1 and 2 leaks and reported to have been repaired. Both the P&G Inspectorate and third party organisation results confirmed that these leaks had been repaired and no well head reportable leaks were identified. Some minor insignificant leaks were detected on some well pumping equipment (as outlined above)

In addition to the well head inspection program, the P&G Inspectorate conducted inspections of well pumping equipment such as stationary engines. This equipment varies depending on the manufacturer, however in some cases the Inspectors identified non-compliance with Australian Standards. These findings were forwarded to the relevant manufacturers and operators for immediate action.

The P&G Inspectorate also requested the assistance of Simtars to assist with atmospheric monitoring around wells, gas stream sampling and gas engine exhaust emissions. The purpose was to test the atmosphere surrounding the well head and associated equipment for emission levels that may be above the exposure level. The test results were analysed with no significant findings and a copy of the report has been placed on the Departmental web site. www.dme.qld.gov.au/mines/test_results_from_tara_gas_samples.cfm .


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www.dme.qld.gov.au/mines/test_results_from_tara_gas_samples.cfm

6

7

Systemic safety improvement – Code of Practice

At the request of the P&G Inspectorate, the Australian Petroleum Production and Exploration Association (APPEA), formed a technical advisory committee to create consistent best practice industry policies in regard to technical safety standards for CSG activities.

The first task of this committee was to develop a common approach to risk management of well heads. This was to include monitoring, remediation controls and a consistent approach to well head inspection and measures to address leaks.

A draft “Code of Practice” by the committee overseen by the P&G Inspectorate was prepared in late 2010. A number of subsequent drafts and iterations occurred and the Code has been finalised. The Code has now been published and is available from the Departmental website at: http://www.dme.qld.gov.au/mines/technical_information.cfm .

A standard leak measuring methodology has been adopted for the industry under this “Code of Practice”. This methodology requires gas/air content to be measured at 150mm from the source, with all leaks above 10% LFL being reportable. This exceeds the current standard level of 20% LFL at 200mm distance used by some major operators in gas processing plants which have significant gas infrastructure often in confined spaces. It represents a very conservative approach to the classification of reportable leaks and it meets or exceeds the requirements of the AS/NZS: 4645.1:2008 ‘Gas distribution Network - Network Management’ standard used in urban environments.

Well head reportable leaks identified under the “Code of Practice” must be actioned and reported in accordance with Codes’ requirements.

From 15 April 2011, the Code has been called up as a safety requirement as a preferred standard in Schedule 1 of the P&G Regulation. It is an offence under the P&G Act not to comply with a safety requirement. A number of companies implemented some of the principles and methodologies from the draft code as it was developed in advance of this formal requirement.

Future action

The Queensland Government is committed to maintaining a high standard of petroleum and gas safety and health for all workers in a complex and rapidly expanding industry. The P&G Inspectorate is committed to ensuring well head safety in Queensland through a state-wide compliance program which includes a range of education, monitoring and enforcement activities.

To ensure that the enforcement program can operate effectively and in line with industry growth, nine new Inspectors and one Investigator have been appointed. These additional Inspectors will ensure the frequency of industry monitoring and coverage of inspections and audits continues to be effective as the industry continues to grow in size and complexity.

The P&G Inspectorate has not only increased numbers operating compliance programs from its Brisbane Southern Region office, but also has Inspectors based in Toowoomba, Dalby and Roma. The increased numbers of Inspectors will allow a greater presence in the Surat Basin with regard to all CSG activities.


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http://www.dme.qld.gov.au/mines/technical_information.cfm

8

A program of on-going, planned and random inspections of wells will continue throughout 2011 to ensure compliance with the well head safety inspection program and reporting requirements.

Where the response to compliance directions may not have met the requirements (either because of time delays or not undertaking repairs as required), further compliance action is under consideration.

The P&G Inspectorate seeks to work with industry in a co-operative manner to ensure compliance and includes education and advice to encourage compliance with the provision of Legislation. Where these methods do not result in compliance, further enforcement tools used by the P&G Inspectorate include the issue of CD’s to undertake rectification actions; dangerous situations notices to stop plant operating, inspection and audit reports, safety management plan validation notices, the undertaking of high level compliance meetings and prosecution.

Conclusions

The well head safety program was instigated in response to concerns raised by property owners in the Tara area about leaking CSG wells. All companies were directed to undertake a full inspection of wells and this identified that a small percentage of wells did have leaks of concern. Only five of these were at a level where the risk of the leak posed an unacceptable level of risk to the community and required immediate repair. A further 29 were below the LFL but at a level where good safety practice dictates that action should be taken. These leaks have also been repaired.

Leaks at well heads and their associated facilities are minimised by design standards and robust safety obligations. If leaks do occur they do not provide for significant risk to the workforce or the community. This is due to their isolated nature, signage and fencing, the nature of natural gas, which is lighter than air, and the exclusion of ignition sources around the equipment.

Nevertheless, the program has highlighted a number of areas for improved practice including:

• Improved CSG industry awareness of best practice standards and safety outcomes;

• Industry standard for inspection and testing techniques for gas leak detection;

• Classification and reporting definitions for gas leaks;

• Use of gas detection equipment:

• Improved fencing and security arrangements for wells:

• Standardised reporting and action criteria for remediation;

• The need for asset integrity programs including maintenance and inspection: and

• Legacy wellhead equipment to be closely monitored and replaced in an on-going program.

Improvements have been made in all areas. In particular, the development of a “Code of Practice” for inspection, reporting and remediating leaks provides for a consistent approach to this issue across the whole industry resulting in a systemic safety improvement of the industry.

The P&G Inspectorate will continue to undertake announced and unannounced inspections of well head facilities and review company practice and compliance.


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The Queensland Government is committed to ensuring the CSG industry proceeds safely, in terms of the environment and community expectations. The Government has recently, employed more P&G Inspectors to monitor the activities of this growing industry and intends to closely monitor its development and ensure continued high levels of compliance.


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APPENDIX I - Summary of category 1 and 2 leaks

Category 1 (>100% LFL) leaks (in flammable range)

Company Leak finding Leak position

QGC Lauren 80

5% gas in air Located at pump drive head stuffing box gland seal

QGC Codie 7

5% gas in air Located at pump drive head stuffing box gland seal

QGC Berwyndale South 79

12% gas in air Located on two inch to three quarter inch reducer leak on branch line on Foxboro transmitter

QGC Champagne Creek 3

21% gas in air Unplugged ball valve above casing 24/08/10

QGC Myrtle 1

5% gas in air Located on drain point of Dominick Hunter filter

Category 2 (>10% LFL to 100% LFL) leaks (below flammable range but still actionable)

Company LFL Leaks Leak Type Action Arrow Energy

Tipton West 094 27% LFL @ source

Rope gland packing on drive head

Repaired

Arrow Energy Tipton West 068T

37% LFL @ source

Electronic cable gland packing

Repaired

Arrow Energy KN Pilot 1

10% LFL @ source

Casing Leak Repaired

Bow Energy Orallo North 3

30% LFL @ 20mm

At the mandrill Repaired

Origin Peat 14

23% LFL @ 50mm from source

On packing gland on wiring valve to meter run

Repaired

Origin Peat 20


From micro annulus Repaired

Origin Peat 36


From top of well head Repaired


50% LFL From flexible hose from the power head drive

Repaired


15% LFL From top of the Oillift top drive power head

Repaired


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Company LFL Leaks Leak Type Action


16% LFL Kimray gas regulator on pipe line to separator skid

Repaired


20% LFL On stem of the valve on top of the ball valve and thread on pressure gauge

Repaired


65% LFL At base of Domnick hunter drain valve

Repaired

QGC Argyle 2

48% LFL1 At base well at casing Repaired

QGC Argyle 9

21% LFL At base well at casing Repaired

QGC Bellevue 12

22% LFL At upper vent hole of Kimray valve on water line

Repaired

QGC Argyle 36

22% LFL From surface casing between the poly sheath and the drive head on C/tree

Repaired

QGC Berwyndale 6

10% LFL at ground level at base of the well head

Repaired

QGC Bellevue 17

10% LFL Stem of gate valve on lower arm or well head

Repaired

QGC Bellevue 10

10% LFL At crystal test point at three way to the pressure indicator

Repaired

QGC David 5

12% LFL Cable gland Repaired

QGC Lauren 43

34% LFL From screwed head of well head flange

Repaired

QGC Lauren 77

20% LFL From screwed head of well head flange

Repaired

QGC Lacerta 8 / Janus 10

10% LFL Thread on Swagelok fitting Repaired


95% LFL Gland on cable Repaired

QGC Kenya East 8

80% LFL Cable gland on well head Repaired


27% LFL Down hole gauge cable Repaired

Santos Fairview 40

14% LFL Polish rod packing on gland Repaired

Westside Paranui 5

15 % LFL Ball valve outlet Repaired

Westside Tilbrook 8

19% LFL Pump Shaft packing gland Repaired

Note 1

Initially, the QGC Argyle #2 well was reported as a category 2 with readings of 48% LFL around the casing. The soil around the well was excavated to expose the concrete surrounding the casing, during this period the leak increased to a category 1 due to the exposure of the casing. A workover rig was contracted to plug and abandon the well to isolate the leak source.


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This activity was later found to be unsuccessful as minor ‘parts per million’ (PPM) was detected after the repair. QGC were directed by the Inspectorate to have a workover rig return to the well to fully isolate the well. This was successfully conducted in late February 2011. The well was subsequently monitored for several weeks which resulted in no hydrocarbons being detected. The Inspectorate conducted gas independent gas detection sampling in March and April 2011 and detected no hydrocarbons.


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Coal seam gas well head safety program final report · Coal Seam Gas Well Head Safety Program Final...

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