© BP p.l.c.
Security Classification:
BP Internal
New Ventures
Great Australian Bight
Exploration Drilling Program
Stromlo-1 and Whinham-1
ENVIRONMENT PLAN OVERVIEW
(EPPs 37, 39)
Rev
14 September 2016
0
Uncontrolled when printed or stored locally
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Table of Contents
1
Introduction ................................................................................................................. 1
1.1 Proponent ......................................................................................................... 1
1.2 Legislative Framework ...................................................................................... 2
2
Activity Description ..................................................................................................... 3
2.1 Activity Overview .............................................................................................. 3
2.2 Activity Location ................................................................................................ 3
2.3 Operational Details ............................................................................................ 5
2.3.1
2.3.2
2.3.3
2.4
Mobile Offshore Drilling Unit ................................................................................ 5
Support Vessels ................................................................................................... 5
Aviation Operations .............................................................................................. 5
Drilling Program ................................................................................................ 5
2.4.1
2.4.2
2.4.3
2.4.4
2.4.5
2.4.6
Timing and Schedule ............................................................................................ 5
Well Design and Drilling Methodology ................................................................. 6
Drilling Fluids........................................................................................................ 6
Drilling cuttings and fluid discharge ...................................................................... 6
Well evaluation..................................................................................................... 7
Plug and abandonment of well ............................................................................. 7
3
Stakeholder Consultation ............................................................................................ 8
3.1 Identifying relevant persons, and their functions interests and activities .......... 8
3.2 Providing ‘sufficient information’ to make an informed assessment. ............. 12
3.3 Providing a ‘reasonable period’ for consultation.............................................. 13
3.4 Consultation Outcomes .................................................................................. 13
3.5 Ongoing Consultation ..................................................................................... 28
4
Description of the Existing Environment ................................................................... 29
4.1 Research ........................................................... Error! Bookmark not defined.
4.2 Physical Environment ...................................................................................... 29
4.2.1
4.2.2
4.2.3
4.2.4
4.2.5
4.3
Ecological Receptors ....................................................................................... 31
4.3.1
4.3.2
4.4
Climate............................................................................................................... 29
Bathymetry ........................................................................................................ 29
Oceanography .................................................................................................... 29
Ambient Ocean Sound ....................................................................................... 30
Hydrocarbons ..................................................................................................... 31
Shoreline ............................................................................................................ 31
Marine and Coastal Waters ................................................................................ 32
Social Values ................................................................................................... 40
4.4.1
4.4.2
4.4.3
4.4.4
Marine Bioregions .............................................................................................. 40
Offshore Protected Areas .................................................................................. 41
Onshore Protected Areas ................................................................................... 43
Coastal Settlements ........................................................................................... 43
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4.4.5
4.4.6
4.4.7
4.4.8
4.4.9
4.4.10
4.4.11
Commercial Fishing and Aquaculture ................................................................. 44
Recreational Fishing ........................................................................................... 44
Commercial Shipping ......................................................................................... 45
Tourism and Recreation ..................................................................................... 45
Cultural Heritage ................................................................................................ 45
Petroleum Exploration and Production ............................................................... 46
Defence Activities .............................................................................................. 46
5
Environmental Impact and Risk Assessment ............................................................ 46
6
Environmental Impact and Risk Evaluation – Accidental Release.............................. 52
6.1 Risk Management within BP........................................................................... 52
6.2 Lessons from Deepwater Horizon .................................................................. 52
6.2.1
6.2.2
Incorporating Lessons Learned .......................................................................... 58
Progress on Recommendations of the Bly Report.............................................. 59
7
Environmental Impact and Risk Evaluation – Oil Spill Response Activities ............... 66
8
Summary of Response Arrangements in the Oil Pollution Emergency Plan ............. 69
8.1 Support Arrangements .................................................................................... 69
8.2 Response Strategy Overview ......................................................................... 70
8.2.1
8.2.2
8.2.3
8.2.4
9
Implementation Strategy ........................................................................................... 72
9.1 The BP Operating Management System ........................................................ 72
9.2 Contractor Management System .................................................................... 73
9.3 Roles and Responsibilities .............................................................................. 73
9.4 Training and Competencies............................................................................. 73
9.5 Incident Recording and Reporting ................................................................... 74
9.6 Environmental Monitoring and Record Keeping .............................................. 74
9.7 Auditing and Review ....................................................................................... 75
9.7.1
9.7.2
9.7.3
9.7.4
9.7.5
9.7.6
10
At-Sea Response Strategy ................................................................................. 70
Near-shore Response Strategy........................................................................... 71
Shoreline Response Strategy ............................................................................. 72
Oiled Wildlife Response Strategy ....................................................................... 72
Audit and Verification ......................................................................................... 75
Rig verification ................................................................................................... 75
Support vessel audits ......................................................................................... 75
EP Compliance Audits ........................................................................................ 76
OPEP and OSMP readiness review .................................................................... 76
EP and OPEP Review......................................................................................... 76
References ................................................................................................................ 77
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1
Introduction
In 2011, BP Developments Australia Pty Ltd (BP) was awarded four exploration permits in
the Great Australian Bight (GAB) adjacent to South Australia (SA): EPP37, EPP38, EPP39
and EPP40. BP (as operator) proposes to drill two exploration wells as part of an initial
drilling program: Stromlo-1 and Whinham-1.
Stromlo-1 is located approximately 600km west of Port Lincoln and 400km southwest of
Ceduna, in a water depth of approximately 2250m. Whinham-1 is located approximately
600km west of Port Lincoln and 350km southwest of Ceduna, in a water depth of
approximately 1150m.
The wells will be drilled using a semi-submersible mobile offshore drilling unit (MODU).
The drilling program is scheduled to commence in Q4 2016 to Q1 2017. It is anticipated
that each well will take approximately 75 days to drill. In the event of any technical or
equipment delays the duration may be greater, so the assessment for each of the wells
has allowed for up to 150 days per well.
This activity is a subset of the broader activity covered by the proposed Great Australian
Bight Exploration Drilling Environment Plan (“GAB EP”), for which BP has an Opportunity
to Modify and Resubmit by 31 December 2016. The first two wells, covered by this EP,
will be excised from the scope of the GAB EP before it is resubmitted. Consultation about
the GAB Exploration Drilling Program has been ongoing since December 2014, and related
information is available at www.bpgabproject.com.au.
1.1
Proponent
BP and Statoil are the registered titleholders of EPPs 37, 38, 39 and 40, with BP being the
Operator. BP is wholly owned by BP Australia Group Pty Ltd and is ultimately owned by BP
p.l.c (a company registered in England and Wales).
BP is an international oil and gas companies, operating in over 75 countries. In Australia, BP
is a foundation investor and one of six equal joint venture partners in the North West Shelf
Venture (NWSV) and also has interests in the Browse basin.
Statoil is an international energy company headquartered in Norway, with operations in 37
countries. In Australia, other than its interests in the GAB, Statoil has acquired the WA-506P exploration permit off the Western Australian (WA) coast.
The BP operating office is located in Perth at:
Level 8, 250 St Georges Terrace
Perth, Western Australia, 6000.
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1.2
Legislative Framework
The proposed activity is located in Commonwealth waters off the SA coast. Petroleum
activities undertaken in this area are regulated entirely by Commonwealth legislation and
primarily under the Offshore Petroleum and Greenhouse Gas Storage (OPGGS) Act 2006
and associated regulations. The OPGGS (Environment) Regulations 2009 specify the
requirements to manage the environmental impacts of petroleum activities. Key to these
Regulations is the submission of an EP to the regulatory authority (NOPSEMA) for
acceptance prior to commencing the proposed activities. In addition to the EP, several
other plans will be submitted to NOPSEMA prior to drilling, including an Oil Pollution
Emergency Plan (OPEP), an Operational and Scientific Monitoring Plan (OSMP), a MODU
Safety Case and Safety Case Revision and a Well Operations Management Plan (WOMP).
Since February 2014, NOPSEMA’s environmental management authorisation process has
been endorsed by the Federal Minister for the Environment as a Program (the Program)
that meets the requirements of Part 10, section 146, of the EPBC Act. Under the Program,
the Minister for the Environment has approved a class of actions which, if undertaken in
accordance with the endorsed Program, will not require referral, assessment and approval
under the EPBC Act. Petroleum and greenhouse gas activities undertaken in
Commonwealth waters in accordance with the Program are “approved classes of action”.
The Program has objectives which include ensuring activities undertaken in the offshore
area are conducted in a manner consistent with the principles of ecologically sustainable
development and will not result in unacceptable impacts to matters of national
environmental significance (MNES) protected under Part 3 of the EPBC Act.
The EP provides an appropriate level of consideration of the potential impacts to protected
matters. This has included making specific reference in Section 4 to the values of matters
protected under Part 3 of the EPBC Act using references and relevant guidance documents
to be considered, such as EPBC Act significance guidance documents, relevant policy
statements, plans of management, recovery plans and on-line databases.
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2.1
Activity Description
Activity Overview
Stromlo-1 and Whinham-1 will be drilled using the Ocean GreatWhite semisubmersible
MODU. The MODU will be supported by a fleet of support vessels and three helicopters.
The MODU is considered to be conducting a ‘petroleum activity’ from the time the MODU
arrives at each well location, until the time the MODU demobilises from each well location.
A 500 m Petroleum Safety Zone (PSZ) will be gazetted around the MODU when it is on
location via a notice published in the Government Gazette, in accordance with the OPGGS
Act. Support vessels are considered part of the petroleum activity while they are within the
500-m radius PSZ around the MODU. The 500-m radius PSZ limit has been selected
because within this zone, the support vessels must comply with the MODU operating
procedures as detailed in the MODU’s Facility Safety Case. When the MODU and vessels
are outside the PSZ (e.g., steaming to or from location, or holding position outside the PSZ)
and remain within Australian waters, they come under the regulatory jurisdiction of AMSA
under the Navigation Act 2012 (Cth). Accordingly, this EP (and associated OPEP) does not
cover activities performed by the support vessels while outside the PSZ. The supply
vessels will resupply via a supply base in Port Adelaide. The supply base is regulated by
SA authorities, and is outside the scope of this EP.
As with the support vessels, helicopters are considered part of the petroleum activity while
they are within the 500-m radius PSZ around the MODU. This EP does not cover activities
performed by the helicopters while outside the PSZ. At all times, helicopter operations
come under the regulatory jurisdiction of the Civil Aviation Safety Authority (CASA) under
the Air Navigation Act 1920 (Cth), Civil Aviation Safety Regulations 1998 and the Federal
Aviation Regulations.
2.2
Activity Location
The Ceduna sub-basin is located on the southern margin of Australia in the GAB. Stromlo-1
and Whinham-1 are located approximately 600 km west of Port Lincoln respectively and
400 km and 350km southwest of Ceduna respectively.
Stromlo-1 is at a depth of approximately 2250 m and Whinham-1 at 1150 m. The locations
of the wells are shown in Figure 1.
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Figure 1 – Stromlo-1 and Whinham-1 well locations
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2.3
Operational Details
2.3.1
Mobile Offshore Drilling Unit
The wells will be drilled using the Ocean GreatWhite semi-submersible MODU. The MODU
is owned and operated by Diamond Offshore General Company (Diamond).
The Ocean GreatWhite is a Moss CS60E design, sixth generation harsh environment semisubmersible MODU. This MODU is designed to operate in water depths from 150 to 3,000
m and a drilling depth of up to 10,670 m measured depth. It has been designed to operate in
harsh weather environments, such as the conditions that may be experienced in the GAB.
2.3.2
Support Vessels
A fleet of vessels will be used to support the drilling campaign, and will be based out of Port
Adelaide. The fleet will be dimensioned and selected to ensure they can efficiently fulfill the
following functions:
•
Supply food, fuel and bulk powders, drilling fluid and drilling materials;
•
Collect waste;
•
Assist in emergency response situations; and
•
Monitor the 500-m radius PSZ around the MODU and intercept errant vessels.
To achieve those objectives, vessels of different sizes and capabilities will be considered,
collectively referred to herein as support vessels.
There will be one vessel on standby at all times during the operations to provide support
capability for the MODU in accordance with the MODU’s Facility Safety Case. The vessels
will hold station using DP.
Vessel crew changes are typically every 28 days and will be carried out alongside in port.
Refueling of the support vessel fleet will also take place within port.
2.3.3
Aviation Operations
Ceduna is the main base for BP’s helicopter operations in support of the Stromlo-1 and
Whinham-1 Exploration drilling program. Helicopter operations to the MODU are planned as
required but usually will be one return flight each weekday.
In addition to the existing helicopter re-fueling facilities in Ceduna, helicopter re-fueling will
take place on the MODU. Refueling will be undertaken in accordance with MODU-specific
procedures.
2.4
Drilling Program
2.4.1
Timing and Schedule
The drilling program is scheduled to commence in Q4 2016 to Q1 2017. It is anticipated that
each well will take approximately 75 days to drill, however this duration is based on an
average. In the event of any technical or equipment delays, this duration may be greater. As
such the basis for the assessment for each of the wells has been up to 150 days.
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2.4.2
Well Design and Drilling Methodology
The well design and drilling methodology for each well is detailed in the well specific Well
Operations Management Plan (WOMP), which is required to be accepted by NOPSEMA
prior to commencement of drilling. At the completion of drilling operations, a series of
cement and mechanical plugs will be set within the wellbore, and the well will be plugged
and abandoned in accordance with the WOMP.
2.4.3
Drilling Fluids
Drilling fluids (or muds) will be used during the drilling program to provide a range of
functions, including:
•
Control of formation pressures (i.e., providing a hydrostatic head by managing mud
density maintains well stability and prevent a blowout);
•
Wellbore stability through mud weight and chemical inhibition;
•
Transport of drill cuttings out of the hole to the MODU;
•
Maintenance of drill bit and assembly (i.e., lubrication, cooling and support); and
•
Sealing of permeable formations to prevent formation invasion
The drilling methodology proposes the use of a combination of seawater with high viscosity
sweeps and synthetic based mud (SBM).
The selection of drilling fluids to be used during the drilling program is undertaken through
an evaluation of the technical, safety and environmental attributes. The Great Australian
Bight Exploration Program Chemical Assessment Guideline defines the process for the
assessment of the offshore operational use and discharge of chemicals for the project.
2.4.4
Drilling cuttings and fluid discharge
Consistent with industry practice, all cuttings generated by riserless drilling (ie in the first
sections of the well bore) will be returned directly to the seabed where they will be
deposited in the vicinity of the wellhead. Once the riser is in place, cuttings and muds will
be returned to the MODU.
On the MODU, the mud returns carrying the drilled cuttings will initially pass through a shale
shaker where the majority of mud will be separated from the cuttings, before cuttings are
discharged overboard. When SBM is used, cuttings from the shale shaker will be passed
through a cuttings dryer, which will further remove SBM from cuttings. Tests will be
conducted to determine the Retention on Cutting (ROC) for SBM to ensure that no more
than 6.9% by weight on wet cuttings is discharged overboard.
Drilling fluid will be re-circulated via the riser for reuse in the wellbore. No bulk SBM
discharges will be permitted. Any unused or recovered SBM will be shipped back to port and
inspected by the mud systems contractor. If it is subsequently determined that the
properties of the recovered back-loaded SBM cannot be reconditioned at the onshore
treatment facility, the SBM will be disposed of at an authorised waste management site.
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2.4.5
Well evaluation
The well will be evaluated using Logging While Drilling (LWD) techniques and mud logging.
Wireline logging and formation testing/sampling may be performed based on the results of
the primary evaluation tools.
Wireline evaluation will be undertaken to determine rock and fluid properties of the targets.
A suite of standard wireline logs will be run, including gamma ray, neutron-density,
resistivity, sonic, acquisition of pressures and samples, vertical seismic profiling (VSP) and
side wall coring.
A VSP will be conducted to tie the well bore to the existing 3D seismic dataset, to refine the
geological prognosis and aid with casing shoe placement. VSP operations involve deploying
an acoustic sound source from the MODU or support vessel, while a number of receivers
(geophones) are positioned at different levels within the drilled hole to measure the travel
time.
Typically, between three and six air guns are used during a VSP, with a volume of between
150 - 250 cui each. The source is generally positioned at 5-10 m below water surface. Zerooffset VSP operations, proposed for this drilling program, are typically of short duration,
normally taking not more than a day to complete. Two VSP operations are planned for each
well, and each will also have a source test 48 hours before VSP operations commence.
Whilst VSPs are quieter and shorter in duration than exploration seismic surveys, measures
outlined in the EPBC Act Policy Statement 2.1 ‘Interaction between offshore seismic
exploration and whales’ (DEWHA, 2008) will be implemented during VSP.
2.4.6
Plug and abandonment of well
All wells drilled will be permanently plugged and abandoned after completion of data
acquisition and evaluation programs, in accordance with applicable BP practices and the
WOMP. Plug and abandon procedures are designed to isolate the well and mitigate the risk
of a potential release of wellbore fluids to the marine environment.
Plug and abandon operations will involve setting a series of cement and mechanical plugs
within the wellbore, including plugs above and between any hydrocarbon bearing intervals,
at appropriate barrier depths in the well and at the surface. These plugs are tested to
confirm their integrity.
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3
Stakeholder Consultation
The consultation that has been conducted in the course of preparing this EP has been
ongoing since December 2014 and has comprised a number of iterative stages, underpinned
by the publication of materials on the project website, and supplemented by additional
bespoke engagement on specific issues with specific relevant persons where necessary.
This consultation has been conducted in respect to a broader scope of petroleum activities
than that covered by this EP, i.e. BP’s initial proposed EP to drill four wells anywhere within
a 12,100km2 area (including the locations of Stromlo-1 and Whinham-1). This EP represents
a contraction of scope relative to the broader drilling area EP. It does not include any new or
different activities (rather a subset of the activities within the four well program), or new or
different risks or impacts to the environment or to the functions, interests and activities of
relevant persons, nor to any new relevant persons. All previous consultation undertaken in
respect to the four well program is relevant to this EP. Additional consultation has been
undertaken to update stakeholders regarding the proposed scope of this EP, and will
continue leading up to and during drilling operations.
3.1
Identifying relevant persons, and their functions interests and
activities
In accordance with the regulations, BP describes five categories of relevant persons. The
first two categories are the respective Commonwealth and relevant State/Territory
Government departments that may be relevant based on the activities proposed.
NOPSEMA’s Guideline (NOPSEMA, 2016) states “This is taken to mean a Government
Department or agency that has responsibility for managing the marine environment. This
may include those with responsibilities for environmental and fisheries management,
defence and communications, maritime/navigational safety, marine parks and native title.”
However, reflecting the broader interest in the holistic potential of oil and gas exploration
and development, BP has not limited itself to this guidance and for example has also
included local government and regional development agencies in the Eyre Peninsula as
having a relevant interest.
The third category is the “Department of the responsible State Minister, or the responsible
Northern Territory Minister” and in this instance is the South Australian Department of State
Development (DSD). DSD has also provided invaluable assistance in coordinating the input
of other relevant South Australian agencies consulted under the second category, above.
The fourth category is “a person or organisation whose functions, interests or activities may
be affected” by the proposed activities. The Regulations further describe the meaning of the
terms ‘functions’, ‘interests’ or ‘activities’:
•
‘Functions’ are a person or organisations power, duty, authority or responsibilities.
•
‘Activities’ are a thing or things that a person or group does or has done.
•
‘Interests’ are a person or organisation’s rights, advantages, duties and liabilities; or a
group or organisation having a common concern.
The fifth category is “any person or organisation that the titleholder considers relevant” and
in this category BP has chosen to include elected representatives, regional development or
indigenous agencies, and environmental issue motivated groups (IMGs) that have either
expressed an interest in the activity or have a track record of expressing interest in similar
activities in Australia.
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Relevant stakeholders were identified from a ground-up evaluation of the economic, social
and environmental interests in the GAB that was initially developed for BP’s 2011 marine
seismic survey. This existing stakeholder database has been further refined according to
BP’s ongoing consultation. Internet publication of relevant project information has further
enabled the self-nomination of other interested parties.
The justification of how BP has identified which stakeholders to consult in this scenario is
contained below in Table 1. Table 1 contains a list of the stakeholders considered to be
relevant persons and therefore consulted in connection with each of these categories during
the preparation of this EP, together with why BP considered their functions, interests and
activities to be relevant.
Table - 1: Identification of relevant persons
Person or organisation
Relevance to the activity
Relevant persons identified pursuant to Regulation 11A(1(a)): each Department or agency of
the Commonwealth to which the activities to be carried out under the EP, or the revision of
the EP, may be relevant.
Department of the Environment (DOE)
DOE has responsibility for the Environment
Protection and Biodiversity Conservation
(EPBC) Act which regulates significant
environmental impacts upon matters of
national environmental significance,
including threatened species, migratory
species and the Commonwealth Marine
Area. DOE also has responsibility for the
establishment and regulation of a network of
Commonwealth Marine Reserves, some of
which overlap with the activity area.
Australian Maritime Safety Authority (AMSA) AMSA is responsible for legislation relating
to safe navigation at sea and the interaction
of the activity with other shipping traffic.
AMSA is responsible for the National Plan
for Maritime Environmental Emergencies
and has been separately engaged on the
formulation of the OPEP associated with this
EP.
Australian Fisheries Management Authority
AFMA is responsible for the management of
(AFMA)
fisheries in the Commonwealth Marine Area,
including whether any marine pollution
incident could lead to their closure.
Department of Defence (DOD)
DOD was considered a relevant organisation
in case military training operations were
planned to coincide with the activity.
Australian Communications and Media
ACMA was considered a relevant
Authority (ACMA)
organisation because under the
Telecommunications Act (1997) it has
responsibility for the installation and
protection of submarine cables.
Relevant persons identified pursuant to Regulation 11A(1(b)): each Department or agency of
a State or the Northern Territory to which the activities to be carried out under the EP, or the
revision of the EP, may be relevant.
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South Australian Department of Planning,
These agencies include those with
Transport and Infrastructure (DPTI)
responsibility for environmental
management in coastal waters and upon the
South Australian Department of
coastline, eg for state fisheries. In addition
Environment, Water and Natural Resources
SARDI conducts research throughout the
(DEWNR)
GAB, and SAPOL has a role as a law
DEWNR Manager of GAB Marine Park
enforcement agency including in the
South Australian Environmental Protection
Commonwealth Marine Area where called
Authority (EPA)
upon to do so.
South Australian Department of Primary
DPTI is the SA Lead Agency (and DOT the
Industries and Regions (PIRSA)
WA Lead Agency) for combatting oil spills
South Australia Police (SAPOL)
under the National Plan, whilst SA EPA and
South Australia Research and Development
WA DPAW have responsibilities for
Institute (SARDI)
Western Australian Department of Transport environmental management in the coastal
Western Australian Department of Fisheries areas of SA and WA respectively.
Western Australian Department of Mines
and Petroleum
Western Australian Department of Parks and
Wildlife
Relevant persons identified pursuant to Regulation 11A(1(c)): the Department of the relevant
State Minister, or the responsible Northern Territory Minister
South Australian Department of State
DSD is the Department of Hon Tom
Development (DSD)
Koutsantonis MP, the relevant State Minister
under the Offshore Petroleum and
Greenhouse Gas Storage Act.
Relevant persons identified pursuant to Regulation 11A(1(d)): a person or organisation
whose functions, interests or activities may be affected by the activities to be carried out
under the EP, or the revision of the EP
Australian Southern Bluefin Tuna Association These fishing organisations were identified
(ASBTIA)
as relevant organisations primarily, but not
limited to, their interests in commercial
South Australian Sardines Industry
fishing in and around the drilling area and/or
Association (SASIA)
of species in the food chain for such
Sarin Group
commercial fishstocks. Some have also
Great Australian Bight Industry Association
been contacted to discuss their involvement
(GABIA)
Commonwealth Fisheries Association (CFA) in oil spill response planning, eg as providers
of Vessels of Opportunity.
Southern Shark Industry Alliance (SSIA)
These fishing organisations were identified
as relevant organisations primarily, but not
South Australian Oyster Growers
limited to, their interests in commercial
Association (SAOGA)
Spencer Gulf and West Coast Prawn Fishers fishing further from the drilling area and/or
along the coastline. Some have also been
Association (SGWCPFA)
contacted to discuss their involvement in oil
Abalone SA
spill response planning, eg as providers of
Northern Zone Rock Lobster Fishery
Vessels of Opportunity.
Association (NZRLFA)
South Australian Marine Scalefish
Association (MSA)
Marine Fishers Association (MFA)
South Australian Mussel Growers
Association (SAMGA)
Seafood Council SA
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Wildcatch Fisheries of South Australia
(WFSA)
Charter Boat Fisheries
Western Australian Fishing Industries
Council
Fowlers Bay Ecotours
This organisation self-identified as relevant
because of its tourism dependency upon the
seasonal presence of cetaceans along the
Eyre Peninsula coastline.
Relevant persons identified pursuant to Regulation 11A(1(e)): any person or organisation that
the titleholder considers relevant
District Council of Ceduna
These persons and organisations were
identified as relevant persons primarily
District Council of Streaky Bay
because, but not limited to, their
District Council of Elliston
representative role in the broad community
District Council of Lower Eyre Peninsula
of the Eyre Peninsula and/or their ministerial
City of Port Lincoln
role in related matters.
Kangaroo Island Council
Eyre Peninsula Local Government
Association
Rowan Ramsey MP, Federal Member for
Grey
Senator Nick Xenophon
Federal Senate Select Committee on
Environment and Communications
Hon Geoff Brock MP, SA Minister for
Regional Development and Local
Government
Peter Treloar MP, SA MP for Flinders
Hon Ian Hunter MP, SA Minister for
Sustainability, Environment and
Conservation
Eyre Peninsula Mining and Energy
These organisations were identified as
Resources Community Development
relevant persons primarily because, but not
Taskforce
limited to, their role in the regional
development of the Eyre Peninsula.
Eyre Peninsula Natural Resources
Management Board
Alinytjara Wilurara Natural Resource
Management Board
Regional Development Australia – Whyalla
and Eyre Peninsula
Far West Native Title Group
These organisations were identified as
relevant persons primarily because, but not
Yalata Community Inc
limited to, their role in native title and
indigenous affairs on the Eyre Peninsula.
Australian Conservation Foundation
Clean Bight Alliance
Conservation Council of South Australia
Friends of Scale Bay
International Fund for Animal Welfare
Sea Shepherd Australia
These organisations were identified as
relevant persons primarily because, but not
limited to, their expressed interest in the
drilling activity and/or their previous interest
in the environmental impact of similar
activities in Australia.
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The Nature Conservancy
The Wilderness Society
Whale and Dolphin Conservation Society
Wild Migration Kangaroo Island
World Wildlife Fund Australia
General Public
3.2
In order to allow other members of the
community to identify themselves as having
a function, interest or activity relevant to the
consultation, BP created a website and
feedback mechanism at
www.bpgabproject.com.au and have used
this as a library for the stakeholder materials
used elsewhere in consultation.
Providing ‘sufficient information’ to make an informed
assessment.
As NOPSEMA’s guideline for deciding on consultation requirements notes, the provision of
information is likely to be iterative and this has been the case with this EP. The approach
adopted by BP has been to progress in phases, with successive approaches to all
stakeholders identified at the time interspersed with bespoke follow-up engagement with
any specific issues raised. The main structure of this iterative staging has been as follows:
•
December 2014: Introductory letter to identified relevant persons with initial information
and seeking expressions of interest in further consultation.
•
February-April 2015: face to face briefings with a range of relevant persons.
•
May 2015: Letter to all identified relevant persons summarising the outcomes of face-toface briefings and including links to website information.
•
July 2015-February 2016: Further various correspondence and meetings with specific
relevant persons on specific points raised. (NB, initial submission of four well strategic
EP in September 2015.)
•
March 2016: Letter to all identified relevant persons summarising the specific
engagement with them to date, leading up to the submission of a second iteration of
four well strategic EP in March 2016.
•
April-July 2016: Further various correspondence and meetings with specific relevant
persons on specific points raised.
•
July 2016: Fact sheet to all identified relevant persons, and published on project website,
providing an update on progress including the focussing of EP scope to Stromlo-1 and
Whinham-1 only; and explaining further information to come.
Where possible, the response to specific issues raised has been made publicly available via
the project website. Key library resources are available at www.bpgabproject.com.au.
BP has adopted a bias to disclosure of information as far as possible, and significant
materials have been published on the project website including sound modelling, cuttings
dispersal modelling, a report on oil spill modelling fate and effects, and a draft summary of
the initial version of a GAB drilling EP, which remains a valid information source about the
proposed activity.
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The project website (www.bpgabproject.com.au) was established in 2013 and is updated
regularly with information for stakeholders to access at their convenience.
3.3
Providing a ‘reasonable period’ for consultation
Most of the stakeholders identified for the project had been identified at the onset of
consultation, and were engaged on multiple occasions during the course of 2015 and into
2016. All stakeholders that had been identified at the time have also received at least two
communications in 2016, including immediately prior to the submission of this EP revision.
This has been a lengthy period of time, and BP believes is more than a reasonable period for
any relevant persons to form a view and engage in discussion with the titleholders.
Throughout the lengthy consultation conducted in support of the preparation of this EP, BP
has stressed the iterative nature of the assessment and consultation process involved in the
development of an EP – and the enduring nature of consultation as part of the
implementation strategy beyond acceptance.
3.4
Consultation Outcomes
The key themes that have been raised during consultation are summarised in Table 2. These
key themes have been provided back to all relevant persons.
In addition, where any relevant person has proposed a measure (whether it technically is a
control measure or some other form of suggestion), the response from BP has been
provided to all relevant persons. A summary of the suggested measures and BPs response
is included below as Table 3.
Table 1 - Key themes raised during stakeholder consultation
Public access to oil spill modelling and oil spill response documents
A number of stakeholders have requested a full copy of the oil spill modelling report, as they
believe that they need to see this report to be assured that BP has adequately planned for oil
spill response.
BP has published its report ‘Fate and Effects Oil Spill Modelling Report: Assumptions,
parameters and results’. BP has also provided a summary of tactical response plans on the
project website. Oil spill modelling has been recently updated for this EP and an updated
version of the Fate and Effects report is being prepared for imminent release. This
information is not strictly necessary for a stakeholder to understand and communicate the
consequence of an oil spill upon their functions, interests and activities and is an example of
BP providing more information than is conventional in order to support EP consultation.
The details of how the project has incorporated lessons learned from the Deepwater Horizon
incident have also been discussed during consultation meetings. Specific information
regarding prevention of loss of well control and technical solutions to a loss of well control
event, such as capping and containment and relief well planning, was provided in the
published draft EP summary.
Prevention of, and response to, a well blowout
A number of stakeholders raised concerns regarding BP’s capacity to prevent oil spills, with
a focus on spills resulting from a loss of well control, particularly in light of the Deepwater
Horizon incident. Specific questions focused on the use of capping stacks and BP’s capacity
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to drill a relief well.
Given this feedback from the initial consultation, BP focused follow up face-to-face meetings
on oil spill prevention and response. Specific information was provided regarding loss of well
control prevention and response measures, as well as details of oil spill planning and
response. These follow up meetings were conducted by BP’s specialists in these areas (the
GAB Engineering Team Leader and GAB Crisis and Continuity and Emergency Response
Manager).
Specific information regarding capping and containment as well as the drilling of relief wells
was provided by the GAB Engineering Team Leader in face-to-face meetings. Information
regarding the various capping stacks available for use, and how these capping stacks may be
used during a loss of well control event were discussed. Details regarding the relief well
planning process were also provided, including information regarding timeframes associated
with drilling a relief well, and how BP would access required resources.
This information has been summarised and included on the project website.
The details of how the project has incorporated lessons learned from the Deepwater Horizon
accident have also been discussed during consultation meetings, with specific information
provided regarding prevention of loss of well control and technical solutions to a loss of well
control event, such as capping and containment and relief well planning. This information is
included in the published Draft EP Summary released in October 2015.
Nevertheless some stakeholders continue to clearly communicate that they would be more
comfortable with equipment such as a capping stack being based locally. This specific
control measure proposal is considered in Table 3 below.
Use of dispersants
A number of questions were raised regarding BP’s plans to use dispersant in the event of an
oil spill, particularly regarding the type of dispersant that would be used, and how they work.
Reference was made to toxic impacts associated with dispersant use in response to the
Deepwater Horizon incident.
BP provided information regarding the types of dispersant that may be used and the
requirements of the Australian Oil Spill Control Agents (OSCA) register (i.e., requirements for
toxicity and efficacy testing of dispersants before they are approved for use in Australia). BP
noted that at this stage eco-toxicity testing is dependent upon analogues because no actual
oil has been discovered in the GAB. However there has been Australian research upon
analogous fishes and molluscs which provides a sound foundation for the risk assessment
of their use in the GAB, with BP willing to provide further specific testing on GAB oil should
any be discovered in commercial quantities.
BP also outlined the decision-making process that would be undertaken prior to deciding to
apply dispersants (i.e., that an operational net environmental benefit analysis would be
conducted as part of oil spill response).
BP has also provided a summary of tactical response plans on the project website, which
includes a summary tactical response plan for dispersant use.
Nevertheless some stakeholders continue to clearly communicate that they wish to see ecotoxicity testing being conducted upon specific local species. This specific control measure
proposal is considered in Table 3 below.
Impact of underwater sound on marine life
A number of questions were raised regarding generation of underwater sound and the
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potential impacts of this sound on marine life.
BP discussed the results of underwater sound modelling that was conducted for the project.
This modelling predicts that the level of sound generated during drilling is highly unlikely to
cause physical or behavioural impacts to sensitive marine species.
The underwater sound modelling report has been made available to stakeholders via the
project website.
A specific proposed control measure suggested by stakeholders (the injection of a curtain of
air bubbles around the rig) is considered in Table 3 below.
Water depths
Most stakeholders asked about the water depth of the GAB wells, and specifically if they
were deeper than ‘normal’ wells.
The exact drilling locations were determined during the course of the ongoing EP
consultation, so specific details of water depths could not be provided in the earliest
engagements. BP advised that the water depths in the drilling area range from
approximately 1,000 m to 2,500 m. Furthermore, BP advised that both these water depths,
along with likely well depths, are similar to wells drilled by BP elsewhere in the world, such
as the Gulf of Mexico, Angola and Brazil.
Economic opportunities from the program
A number of stakeholders were interested in discussing the economic opportunities that
may arise as a result of the drilling program.
BP discussed potential opportunities that will arise in locations such as Ceduna. It was noted
however, that at this early stage of exploration, employment opportunities are limited – and
that this was outside the scope of the EP.
Details were also provided regarding the Industry Capability Network (ICN) portal that BP has
opened to engage with the local supply chain, which encourages potential suppliers to
register interest in order to be informed of future local supply chain opportunities.
Some stakeholders also raised the possibility of a negative impact upon economic
opportunities, for example if the presence of oil and gas industrial activities diminished the
‘clean green’ brand of South Australian seafood or tourism opportunities. Largely this related
to the consequences of an oil spill. Examples of where the oil and gas industry successful
interacts and coexists with fishing and tourism industries featured in a number of
submissions to a Senate Inquiry into petroleum exploration in the GAB.
Public access to the EP
A number of stakeholders have requested a full copy of the EP prior to it being submitted to
NOPSEMA. They believe that being asked to provide input without seeing the full EP is not
possible.
BP began what is now a 20-month consultation process leading up to the submission of this
EP at a time when it had identified key issues, but had not settled upon the answers to
them. Most stakeholders welcomed the fact that BP was prepared to develop its EP through
an iterative process with them, rather than presenting them with a final document.
However, other stakeholders chose to present this inclusive process as a failure to provide
answers from the outset.
Nevertheless, in order to maximise disclosure, BP has provided an outline of what key
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environmental impacts will be assessed in the document, and the mitigation and control
measures that will be implemented to manage these potential impacts. BP has also asked
for stakeholders to identify specific areas that they would like additional information on. As a
result, BP focused follow up face-to-face meetings on oil spill prevention and response.
BP published a draft EP summary on the project website at the same time the first version
of the full EP was submitted to NOPSEMA, rather than after the EP has been accepted by
NOPSEMA. This allowed all stakeholders to review the coverage of issues raised in full, over
a period of time before the submission of subsequent revisions of the EP. .
BP has ensured answers to specific questions raised during EP consultation are shared by
including FAQs on the ‘consultation’ part of the project website. BP has also responded to
specific correspondence that provided more detail on a number of areas throughout the
consultation process.
Opposition to drilling
Some stakeholders indicated broad scale opposition to BP’s plans to drill in the GAB per se
rather than specific aspects of the EP, for example due to opposition to fossil fuel extraction
or exploration in the GAB.
Whilst BP recognises that these are legitimate views for debate in society, and engages
with them in a number of forums such as government policy White Paper processes, it
proved difficult to find areas of constructive discussion and mutual agreement from these
discussions that relate to the EP itself.
Table 2 - Summary of measures proposed during consultation, and titleholder
response
An explanatory note upon this Table
During consultation stakeholders raised a variety of issues. Some were simply questions.
Others were proposals or assertions that did not always neatly fall within NOPSEMA’s
definitions of ‘control measures’ or ‘objections or claims’. BP has therefore included all
significant specific proposals here. This table has been provided to all identified
stakeholders.
Stakeholder
proposal 1:
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/
Stakeholder proposal 1
Access marine traffic information, contact the Joint Rescue
Coordination Centre at start and end of survey, and contact
the Australian Hydrographic Service to enable a Notice to
Mariners two weeks prior to commencement.
“Physical Interaction – other marine users”
Yes
Pre-start notification and their timing (2 weeks) have been
included within Section 9 of the EP. In addition to this,
environmental performance standards have been developed.
Environmental performance outcomes:
EPO 2: All relevant marine users will be notified of Petroleum
Exclusion Zones prior to operations
EPO 3: No damage to other marine user fishing equipment
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standards/
measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
during the course of the petroleum activity.
Performance standards
Measurement criteria
1. Sailing plans for the MODU
1. Contents of sailing
are prepared prior to
plans are provided to
mobilisation to location, for
AMSA.
each rig move, and prior to
demobilisation from the last
well location.
2. Notices to Mariners are
2. Information to
reported to the Australian
communicate a Notice to
Hydrographic Service
Mariners is provided to
delineating the Petroleum
the Australian
Exclusion Zone
Hydrographic Service via
email
[email protected]
two weeks prior to spud.
3. The BP GAB external
3. Consultation database
affairs team ensures that a
and emails are available to
notification flyer, noting the
confirm that notifications
MODU’s location, is issued to
were issued prior to the
stakeholders immediately
MODU arriving on
prior to the MODU’s arrival on
location.
location (i.e. during
mobilisation to site).
n/a
Stakeholder proposal 2
Stakeholder
proposal 2
Locate oil spill response equipment including a capping stack
locally
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/
standards/
measurement
criteria have been
adopted to
manage the risk
“Accidental release – well blowout”
Significant equipment will be available at the drilling location,
in Adelaide and nationally and internationally. However
capping stack location is Singapore and this is explained
below.
Environmental performance outcomes:
No well blowout associated with the drilling program.
Performance standards
Measurement criteria
Safety critical equipment
identified within Section 6.3
of the WOMP from BP
Practice 100222 will be
utilised
Records confirm safety
critical equipment
identified in Section 6.3 of
the WOMP from BP
Practice 100222 are being
utilised
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The fluid and cementing
programmes documented
within the WOMP from BP
Practice 100222 will be
implemented.
Drilling Fluid and Waste
Management Programme
Cementing Programme
Daily drilling reports
A well programme will be
developed prior to spud and
implemented.
Signed off Drilling / Well
program
Daily drilling reports
The Planned Maintenance
System (PMS ) will ensure
safety critical equipment,
specifically the BOP will be
maintained in accordance
with the manufacturer
specifications.
PMS records
Prior to use, the BOP will be
subjected to an Integrated
Acceptance Test (IAT) Part 2
and signed off by BP.
Signed off / dated IAT
records
Prior to use, the BOP will be
subjected to independent
third party verification against
API Standard 53.
Dated records confirm
independent verification
of BOP against API
Standard 53
The BOP will be tested in
accordance with the
frequencies described in the
BOP testing procedure.
Records confirm BOP
tested in accordance with
the BOP testing
procedure.
BP will use a self verification
and oversight model,
described in Section 4.4.2 of
the WOMP to verify well
barriers throughout the
duration of the drilling
program.
Practical barrier checks and
frequency of self verification
and oversight will be
implemented in accordance
with the GWO Safety Plan.
Records confirm practical
barrier checks and
frequency of self
verification and oversight
will be implemented in
accordance with the GWO
Safety Plan
BP’s Competence
Management Programme
(CMP) will ensure all
personnel in safety critical
roles are assessed and the
employees behaviours, skills,
knowledge and understanding
verified to assure
competence.
Records from the CMP
confirm personnel within
safety critical roles are
assessed.
A WOMP will be in place and
accepted by NOPSEMA for
NOPSEMA Acceptance
letter confirms WOMP is
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each well prior to spud.
accepted prior to spud
Environmental performance outcomes:
Mitigate environmental impacts in the event of a well blowout
If not adopted,
why would the
proposal be
grossly
disproportionate?
The programmes OPEP will
be implemented in the event
of a well blowout
IMT log
Incident Action Plan (IAP)
records
Response preparedness will
be undertaken in accordance
with the control measures
identified within the
programmes OPEP.
Pre spud audit
In the event of a well
blowout, the Well
Containment Response Plan
will be implemented.
IMT log
IAP records
In the event of a well
blowout, the relief well plan
will be implemented.
IMT log
IAP records
The programmes OSMP will
be implemented in the event
of a well blowout
IMT log
IAP records
Spill response exercises will
be undertaken as a part of the
drilling programme execution
in accordance with the
programmes OPEP.
Exercise records
BP’s Crisis Management
IMT log
Response System will be
IAP records
implemented in the event of a
well blow out event in
accordance with Section 2 of
the OPEP
A proposal to have a capping stack in the country was
considered. The capping stack that is available to be brought
into Australia was not considered to be technically equivalent
to the OSRL well cap in Singapore. Built for a different type of
operation, the optional capping stack would have required
extensive modifications. It would be more cumbersome to
operate because it requires a Subsea Accumulator Module
(SAM) for closing instead of the ROV torque tool that would
be used for the OSRL cap. In addition, the OSRL cap is
preferred because it would be more erosion resistant and
durable with HH internal trim instead of the EE trim on the
optional capping stack. This option was, therefore, rejected.
Although the cost of the optional stack was not prohibitive,
the surface and subsea infrastructure required to maintain and
operate such a stack would need to be equivalent to the
facilities used by OSRL to store and maintain the capping
stack in its regional centres in Singapore, South Africa,
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Norway and Brazil. The initial preparation time and cost to
build and staff such a facility would be prohibitive for a two or
four well operation.
The OSRL well cap in Singapore is maintained in constant
state of readiness, extensive logistics planning and tabletop
exercises have been performed, and it is supported by an
international collaboration of industry operators. Therefore, it
is the preferred capping solution for the GAB.
The cost of purchasing a new capping stack was also
considered with an estimated cost to be in the order of
US$15,000,000. Construction and acceptance testing time is
estimated to be eight to twelve months. Also, there would
need to be technical specialists and a facility to store, maintain
and regularly function and pressure test the equipment so that
it is kept in an ongoing state of readiness if needed. This
required expertise and facility is not available in country.
Industry specialists are co-located with capping equipment in
Houston and other regional bases including Singapore. This
was not considered a viable or practicable solution because of
relative cost, construction time and lack of available resources.
Estimated costs of having a construction vessel on standby for
capping operation is approximately US$15,000,000 assuming
a 150-day campaign and a day rate of US$100,000. BP is
assessing the Australian and the Southeast Asia markets to
fully understand vessel capabilities and availabilities to identify
vessels that can install a 95-mt capping stack to 2,250- water
depth in the GAB. BP will enter an agreement for “first
refusal” on a vessel capable of deploying the capping stack
prior to drilling into potential reservoir sections.
Although no other options are available at this time, BP will
continue to monitor and evaluate future global well capping
and containment offerings from industry consortia and
commercial entities to determine if more could be done
sooner and identify the potential environmental benefit and
associated cost.
Stakeholder
proposal 3
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/
standards/
Stakeholder proposal 3
Conduct eco-toxicity testing with analogue oils on local fish
species
“Accidental release – well blowout. Response Technique Risk
Evaluation: Planned discharges – dispersants”
No
Environmental performance outcomes:
No disturbance to environmentally sensitive benthic habitats
Performance standards
Measurement criteria
No spraying of dispersants
IMT log
within Threatened Ecological
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measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
Communities (TEC’s) or
southern right whale (SRW)
Calving Biologically Important
Area (BIA).
NEBA completed prior to
operational spraying of
dispersant onto the oil.
Results of NEBA socialised
with DPTI (SA), DoT (WA),
AMSA (Cwlth), NOPSEMA
(Cwlth) and DoE (Cwlth).
NEBA validated during each
operational period (To
consider – spill trajectory,
eco-toxicity data, entrained oil
monitoring results, water
sampling results, feedback
from jurisdictions and
Commonwealth).
Only dispersants listed and
approved on the National Plan
oil spill control agent (OSCA)
register will be used for both
surface and sub-surface
application.
Dispersant/oil ratio adjusted
for optimal dispersion.
IMT log
IAP
IMT log
IAP
IMT log
IAP
IMT log.
Effective log keeps
(volumes sprayed,
locations, etc.).
IMT log.
Effective log keeps
(volumes sprayed,
locations, etc.).
NEBA completed prior to
IMT log.
dispersant spraying. daily
Effective log keep
(volumes sprayed,
locations, etc.).
Dispersant spraying continues
IMT log.
until termination points are
Effective log keep
met.
(volumes sprayed,
locations, etc.).
1. If oil is discovered, BP has agreed to undertake eco-toxicity
testing upon specific GAB species such as Southern Bluefin
Tuna. However in the absence of actual local oil, any additional
studies will provide no added knowledge on impacts which
are reliant on analogues. Other studies on analogous oil,
species and dispersants already exist in Australia for fish and
molluscs and provide a sound foundation for risk assessment.
2. At the time of the Deepwater Horizon incident, eight
dispersants on the US National Contingency Plan (NCP)
Product Schedule were tested for toxicity with findings
indicating that the majority of dispersants were slightly toxic to
practically nontoxic (in accordance with GESAMP 2014). At the
time of the incident, the tests indicate that the dispersant
alone causes less toxic effect than the crude oil. The crude oil
dispersed with the dispersant was found to have the same
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rating as the mechanically dispersed crude oil of ‘moderately
toxic’ to both species. In this case the measured toxic effects
are caused by the oil, not the dispersant (IPIECA-IOGP, 2014;
Hemmer et al. 2011 and Word et al. 2014).
Conclusion: further analogue based research would not add to
the existing comprehensive stock of knowledge. Cost and
delay caused would be grossly disproportionate when there is
a nul potential benefit.
Stakeholder
proposal 4
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/standar
ds/measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
Stakeholder
proposal 5
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/standar
ds/measurement
criteria have been
adopted to
manage the risk
Stakeholder proposal 4
Undertake oil spill modelling at lower thresholds.
“Accidental release – well blowout”
Yes. Oil spill modelling had previously been conducted to
5g/m2 thresholds and this has been now reduced to 1g/m2 to
enable socio-economic impacts to be evaluated.
Environmental performance outcomes:
n/a not a control measure
Performance standards
Measurement criteria
n/a not a control measure
n/a not a control measure
n/a
Stakeholder proposal 5
Deploy a curtain of air bubbles around the rig
“Underwater sound”
No
Environmental performance outcomes:
No harm to marine fauna during the activity
Performance standards
Performance standards
In accordance with Part A.2 of
EPBC Act Policy Statement
2.1, training sessions for VSP
crew are undertaken prior to
conducting the vertical
Attendance sheets verify
that VSP personnel
attended VSP training.
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seismic profile (VSP) to be
able to fulfil the requirements
of A.3 of the policy statement
requirements.
MMOs to be present to
undertake observations
during VSP operations.
Records of MMOs
presence during VSP
operations.
The EPBC Act Policy 2.1 Part
A Standard Management
Procedures (Section A.3) is
implemented during VSP,
which involves the following:
A.3.1-3.2: Start-up procedures
Pre-start visual observations
for 30 minutes out to 3 km.
Soft start, increasing power
over a 30-minute period, with
visual observations out to 3
km.
Delay start up
procedures/power down any
operating acoustic source if
whales are observed within 1
km of the VSP source and
shut down if they approach
within 500 m. Resume soft
start procedures once the
whale has been observed to
move outside the low power
zone (1 km).
VSP operations report
verifies that EPBC Act 2.1
Part A was implemented.
The EPBC Act Policy 2.1 Part
A Standard Management
Procedures (Section A.3) is
implemented during VSP,
which involves the following:
A3.3: Start-up delay
procedures
If during the soft start
procedure a whale is
observed to enter the low
power zone (1 km), the
acoustic source will be
reduced to minimum power.
If a whale is observed within
the shutdown zone (500 m),
the power source will be shut
down.
Soft-start procedures will only
resume after the whale has
been observed to exit the low
VSP operations report
verifies that EPBC Act 2.1
Part A was implemented.
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power zone (1 km) or if the
whale has not been sighted
for 30 minutes.
The EPBC Act Policy 2.1 Part
A Standard Management
Procedures (Section A.3) is
implemented during VSP,
which involves the following:
A.3.4-3.5: Operations
procedure
If a whale is spotted within
the low power zone (1 km),
the acoustic source will be
reduced to minimum power.
If a whale is observed within
the shutdown zone (500 m),
the acoustic source will be
shut down.
Soft-start procedures will only
resume after the whale has
been observed to move
outside the low power zone
(1 km) or if the whale has not
been sighted for 30 minutes.
The EPBC Act Policy 2.1 Part
A Standard Management
Procedures (Section A.3) is
implemented during VSP,
which involves the following:
Night-time and low visibility
procedure
Wherever practicable,
commence VSP during
daylight hours.
Where due to operational
requirements, a VSP must
commence during night-time
or low visibility conditions, the
soft start procedure outlined
previously will be
implemented provided that
there have not been two or
more blue, sperm or southern
right whales observed within
the 3km observation zone
during the preceding 24
hours.
The EPBC Act Policy 2.1 Part
B requirements regarding
increased precaution zones’ is
implemented for Whinham-1
during VSP:
VSP operations report
verifies that EPBC Act 2.1
Part A was implemented.
VSP operations report
verifies that EPBC Act 2.1
Part A was implemented.
VSP operations report
verifies that an increased
‘low power zone’ of 2 km
was implemented during
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A ‘low power zone’ of 2 km
will be implemented during
VSP activities conducted on
Whinham-1 location.
Conduct a passive acoustic
monitoring (PAM) detection
sensitivity study to determine
the value of using PAM
deployed from MODU.
VSP on Whinham-1.
Marine Mammal Observers
(MMOs) will have access to
IR binoculars to assist
observations during VSP
activities conducted during
periods of low visibility.
Evidence of IP binoculars
being made available to
MMOs.
The BP Environment Manager
(or delegate) will report
cetacean sightings online to
the DoE within 3 months of
completion of each well using
the Cetacean Sightings
Application:
http://www.marinemammals.
gov.au/sorp/sightings.
Copies of sighting reports
are maintained to verify
reports were made.
Engines and thrusters are
maintained in accordance
with manufacturer’s
instructions via the Planned
Maintenance System (PMS)
to ensure they are operating
efficiently.
PMS records verify that
engines and thrusters are
maintained to schedule.
PAM detection sensitivity
study conducted prior to
VSP being conducted.
Conduct sound measurement
study to verify the outcomes
of the sound modelling study.
If not adopted,
why would the
proposal be
grossly
disproportionate?
Sound measurement
study has been
conducted, and results
have been reported in the
end of well performance
report.
1. Air provides an effective barrier to sound propagating
through water and has been used to reduce underwater sound
pressures from explosions and other underwater sound.
However, there are significant operational constraints to
implementing bubble curtains in deepwater and upon
investigation no currently available technology would be
capable of being designed around the MODU to reduce
sound.
2. The thresholds for behavioural response by cetaceans to
pulse sounds (eg VSP) are 140-160 db re 1µPa SPL RMS and
for non-pulse (eg thrusters) 120 dB re 1µPa SPL RMS (Table
6.1 in Section 6.5). For fish, no behavioural response threshold
level is identified for non-pulse/continuous sound, but for
pulse the threshold for Temporary Threshold Shift is 186 dB re
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1 μPa2.s SEL (Table 6.1 in Section 6.5). (It should be noted
that these are different sound metrics - SPL RMS and SEL and
therefore should not be directly compared without
conversion). Sound modelling indicates that sound from a VSP
source will decrease to below 140-160 db re 1µPa SPL RMS
approximately 2-4km from the source; and that thruster sound
will decrease to below 160 db re 1µPa SPL RMS within 100
metres and below 120 db re 1µPa SPL RMS between 10 and
40km from source. Therefore any behavioural responses may
result in an undetectable or limited local degradation of the
environment, rapidly returning to original state by natural
action.
Conclusion: there is no technically feasible way of
implementing an air bubble curtain such that it could have a
reductive effect upon an already low consequence impact.
The costs are therefore grossly disproportionate to the likely
benefit.
Stakeholder
proposal 6
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/standar
ds/measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
Stakeholder
proposal 7
What is the
Stakeholder proposal 6
Vary start date outside tuna seasonal migration
“Underwater sound”
No
Environmental performance outcomes:
As per Stakeholder proposal 5 above
Performance standards
Measurement Criteria
As per Stakeholder proposal 5
As per Stakeholder
above
proposal 5 above
1. The behavioural impacts of underwater sound would result
in an undetectable or limited local degradation of the
environment, rapidly returning to original state by natural
action (see proposal 5 above)
2. The standby cost of an MODU which is otherwise ready for
operation is conservatively estimated at $1 million per day.
Conclusion: Given that the sound effects associated with
DP/thrusters are well known, and the impacts are limited, the
costs of implementing this proposal are grossly
disproportionate to the level of benefit / risk reduction
achieved.
Stakeholder proposal 7
Conduct monitoring of actual sound levels generated by
MODU thrusters and associated drilling operations.
“Underwater sound”
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underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/standar
ds/measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
Stakeholder
proposal 8
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/standar
ds/measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
Yes. BP is still assessing the best options for monitoring
actual sound levels.
Environmental performance outcomes:
As per proposal 5 above
Performance standards
Measurement Criteria
Additional performance
Additional measurement
standards included in
criteria included in
Stakeholder Proposal 5 above
Stakeholder Proposal 5
above
Conduct sound measurement
study to verify the outcomes
of the sound modelling study.
Sound measurement
study has been
conducted, and results
have been reported in the
end of well performance
report.
N/a
Stakeholder proposal 8
Transit rig to the GAB and other vessels via west coast of
Australia to avoid introduction of Pacific Oyster Mortality
Syndrome
“Physical presence – biofouling”
Yes, the rig will transit to the drilling area via the west coast.
However rig and vessel transit is out of scope of the EP
(which covers the petroleum activity only) so there are no
relevant outcomes, standards or measurement criteria.
However the stakeholder raising this issue has been informed.
Environmental performance outcomes:
n/a
Performance standards
Measurement criteria
n/a
n/a
n/a
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Stakeholder
proposal 9
What is the
underlying risk to
which the
proposal relates?
Has the
Titleholder
adopted the
proposal?
What
environmental
performance
outcomes/standar
ds/measurement
criteria have been
adopted to
manage the risk
If not adopted,
why would the
proposal be
grossly
disproportionate?
Stakeholder proposal 9
Provide financial support to the South Australian Seafood
Quality Assurance Programme (SASQAP) and consider its role
in OSMP
“Accidental release – well blowout”
Provision of financial support to the SASQAP is considered out
of scope of the EP (which covers the requirements of the
petroleum activity under the OPGGS(E) Regulations) .The
SASQAP is considered in the OSMP.
Environmental performance outcomes:
Mitigate environmental impacts in the event of a well blowout
Performance standards
Measurement criteria
The OSMP will be
IMT log
implemented in the event of a
IAP records
well blowout
1. BP has agreed to consider including SASQAP in the
Operational and Scientific Monitoring programme to be
implemented in the event of a spill.
2. BP has requested relevant stakeholders to provide
proposals for consideration of other support for SASQAP.
BP believes that sufficient information has been provided to stakeholders regarding the key
themes raised during stakeholder consultation. BP will continue to consult with stakeholders
during well planning and operations, and will provide relevant information as it becomes
available.
3.5
Ongoing Consultation
Stakeholder consultation will be ongoing in the lead up to and during the project. BP has
written to all relevant stakeholders informing them of future consultation plans, stating that:
•
BP will contact them proactively should circumstances or BP’s plans change in such a
way as to change the potential impact upon their functions, interests or activities.
•
BP will provide updates of activities on the project website as appropriate
(www.bpgabproject.com.au):
•
−
Shortly before commencement of drilling a well;
−
Monthly updates during drilling of a well;
−
Shortly after completion of drilling a well.
In addition, stakeholders were reminded they can contact BP at any time should they
have additional queries.
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4
Description of the Existing Environment
Oil spill modelling for a worst case credible scenario was undertaken to identify the potential
‘area that may be affected’ (AMBA) by hydrocarbon exposure (also . Modelling indicates that
anywhere along the southern coast of Australia may be contacted by hydrocarbons in the
event of a worst case spill (ie a well blowout), depending on the season that the spill occurs.
The total AMBA has been zoned to reflect the thresholds at which potential impacts to
ecological and social receptors may occur. The impact zones are referred to as:
•
Zone of Ecological Impact (ZoEI) - the zone where the exposure is >10 g/m2 surface, or
>100 g/m2 on shorelines.
•
Zone of social impact (ZoSI) - the zone where the exposure is >1 g/m2 surface or >10
g/m2 on shorelines.
This section describes the environmental, social and cultural features of the AMBA.
4.1
Physical Environment
4.1.1
Climate
Australia’s size and geography gives rise to a diverse range of climate patterns across the
continent and offshore islands; however, the southern and south-east coasts of Australia are
primarily described as being a ‘temperate’ climate.
The GAB is influenced by mid-latitude anticyclones or high-pressure systems that move
from west to east across the region. In summer, the climate is influenced by northerly to
north-westerly winds, while in winter, southerly to south-easterly winds and low pressure
systems bring rainfall. Average monthly temperatures along the GAB coast range from 28°C
in January to 17°C in July. The majority of annual rainfall in the GAB region occurs during the
autumn and winter months (April to August), with an annual average of 272 mm at Eucla and
296 mm at Ceduna (BoM, 2011).
4.1.2
Bathymetry
The seabed in Australian waters is diverse and complex, with recent mapping identifying 21
types of geomorphic features, including major features such as the continental shelf, slope,
plateaus and abyssal plain; and smaller features such as basins, terraces, reefs and
seamounts (State of the Environment Committee, 2011).
The Stromlo-1 and Whinham-1 well locations occur within the continental slope of the GAB.
The continental slope is up to 250 km wide in the GAB and features mid-slope terraces and
numerous deep submarine canyons (GA, 2005), most of which are located to the southeast
of the BP permits. Studies have identified that there are few sensitive seabed features in
the vicinity of the Stromlo-1 and Whinham-1 wells. Two cone-shaped volcanic pinnacles are
located in the northern half of EPP39, known as ‘Anna’s Pimple’ and ‘Murray’s Mount’.
These pinnacles measure approximately 800 m in diameter and 200 m in height (Currie and
Sorokin, 2011), and are located in water depths of about 1,800 m, approximately 20 km and
93 km from Stromlo-1 and Whinham-1 respectively.
4.1.3
Oceanography
Australia is heavily influenced by four major currents: East Australian Current, Leeuwin
current, Indonesian Throughflow, and the Antarctic Circumpolar Current. These four major
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currents have a driving influence on the conditions and biodiversity in Australian oceans and
coastal environments. In addition, there are a number of smaller and more complex current
systems. Four distinct currents occur within the GAB:
1
Leeuwin – comprises waters of low salinity and high temperatures through the whole
water column, originating from the tropical Indian Ocean and passing in an easterly
direction along the continental shelf during winter with speeds up to 1 m.s-1 (Rogers
et al., 2013; DEH, 2005c). During summer, the penetration of the Leeuwin Current into
the GAB is weak to non-existent (Rogers et al., 2013), passing from west to east in a
narrow band mostly during winter (DEH, 2005c; DEWHA, 2007).
2
Central Bight – characterised by warm, highly saline waters derived from the
southwest Indian Ocean around October each year. This current intensifies over
summer and autumn as it spreads east into the GAB where, when combined with the
Leeuwin Current, it provides a continuous band of warm water across the GAB in
winter (DEH, 2005c).
3
West Wind – present in the slope and shelf break parts of the GAB throughout the
year and comprises cold water with low salinity (DEH, 2005c).
4
Flinders – a surface current characterized by cool, low saline waters (Edyvane, 1998)
that runs westwards along the continental slope (DEH, 2005c). It is considered a ‘small
sister’ to the major western boundary currents of the world (Rogers et al., 2013). In
the absence of eddies, these data would indicate the Flinders Current to have an
amplitude of 20 cm.s-1 at depths of 500-600 m and to form part of the Leeuwin
Undercurrent that penetrates the GAB during winter (Rogers et al., 2013).
Oceanographic features within the GAB and wider AMBA include seasonal upwelling zones
(e.g. around Kangaroo Island, or Eyre Peninsula), and mesoscale eddies.
The GAB has a mixed wind wave/swell environment in which at any location the sea-state
rapidly ‘deteriorates’ during the passage of fronts and low-pressure systems, and then
gradually ‘moderates’ as anti-cyclonic conditions return. The wave climate is mildest in
February and most extreme in September (Rogers et al., 2013). Wave height is predicted to
exceed 3 m for 30-60 days of the year and 6 m for 0-10 days of the year.
Modelled average monthly (2006-2010 inclusive) water temperature profiles for the GAB
indicated the monthly average sea surface temperature ranging from about 15°C in
September to just below 20°C in February/March, with a consistent temperature of about
5°C at 1,200 m below the sea surface (APASA, 2011).
Modelled average monthly (2006-2010 inclusive) salinity profiles for the GAB indicated the
monthly average salinity (at the sea surface) stays within the 35.2–35.6 ppm range yearround, and remains about 34.5 ppm at 1,200 m below the sea surface (APASA, 2011).
4.1.4
Ambient Ocean Sound
Ambient sound levels in the GAB were recorded from late 2011 to mid-2012 by sound
loggers that were deployed in the GAB as part of BP’s efforts to investigate underwater
sound characteristics of the area; one near the Head of Bight, and two along the shelf break.
Ambient sound was higher at the shelf break sites compared with the Head of Bight, and
the two shelf break sites showed a steady increase in ambient sound over summer and into
early Winter (McCauley et al., 2012). McCauley et al (2012) found that ambient sound levels:
•
μPa SPL Root
At the Head of Bight – ranged from 73.5 to 131.9 dB re 1
(RMS), with an average of 97.1 dB re 1
μPa (SPL RM S); and
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•
μPa (SPL RM S
At the shelf break - ranged from 74.5 to 144.9 dB re 1
111.7 dB re 1
μPa (SPL RM S).
4.1.5
Hydrocarbons
Studies of the water column chemistry, hydrocarbon degrading microbial communities, and
asphaltite distribution form a component of the GAB Research Program.
Water column samples taken during a number of voyages found that hydrocarbons were
largely absent in the sample set. Seabed sediment samples contained variable amounts of
extractable organic matter.
The overall conclusion from the samples analysed, is that it is unlikely that any thermogenic
hydrocarbons originating from the GAB were encountered and these samples represent
baseline geochemical conditions.
Results from microbial studies show that densities of bacteria in the GAB are typical of
pristine deep ocean environments (Techtmann et al., 2016). The study by Techtmann et al.
(2016) concluded that if a hydrocarbon release occurred in the GAB, it would be expected
that the same groups of bacteria would respond as they did in the Deepwater Horizon
incident.
Surveys for asphaltite and waxy bitumens occurred along the coastline during 2014 and
2015. While the source of asphaltite has not been determined from this study, it is thought
to originate from seeps from exposed tar mats within the offshore Ceduna or Morum subbasins, and is a minor contributor to the natural hydrocarbon loading of SA beaches (McKirdy
et al., 2015). Waxy bitumens originating from Indonesian waters are the most prevalent
bitumen stranding on SA beaches (McKirdy et al., 2015).
4.2
Ecological Receptors
4.2.1
Shoreline
BP conducted shoreline sensitivity mapping along the SA coastline and southern WA
coastline. Sensitivity mapping assists in the development of oil spill response plans,
especially in the identification of sensitive receptors. The Environmental Sensitivity Index
(ESI) shoreline classification system, as outlined in ESI guidelines (NOAA, 2002;
IPIECA/IMO/OGP, 2011) were applied to shoreline habitats; biological and ecological
resources; and socio-economic resources. All three factors: shoreline type, ecological
receptor, and social value, were then combined to produce a cumulative sensitivity map to
understand the comparative overall vulnerability of the shoreline.
Shoreline types (and sensitivity) identified as present along the AMBA coast include:
•
Rocky shores and scarps (ESI 1A, 1C, 2A, 2B); low sensitivity
•
Sandy beaches (ESI 3A, 3B, 4, 5); low to medium sensitivity
•
Gravel beaches (ES 6A, 6B); medium sensitivity
•
Tidal flats (ESI 7, 9A); high to very high sensitivity
•
Mangroves and saltmarshes (ESI 10A, 10B); very high sensitivity
•
Infrastructure (ESI 1B, 8B, 8C); low to high sensitivity.
The most common shoreline types within the AMBA are rocky shores and scarps, and sandy
beaches.
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4.2.2
Marine and Coastal Waters
4.2.2.1
Seagrass
Seagrass typically occurs in shallow subtidal and intertidal environments of estuaries,
sheltered bays or coasts where ocean currents and wave action are not as great. Seagrass
distribution in the GAB is patchy and limited by exposure to swell. Other known locations of
seagrass meadows include Jervis Bay and Botany Bay in NSW, Norfolk Bay and Pittwater in
south-eastern Tasmania, and Corner Inlet, Port Phillip Bay and Western Port Bay in Victoria.
The ‘Posidonia australis seagrass meadows of the Manning-Hawkesbury ecoregion’ is listed
as an ‘endangered’ TEC, and is protected under the EPBC Act. The ecological community
occurs mostly within the sheltered environments of permanently open estuaries along the
warm temperate NSW coastline, from Wallis Lake (32°S) to Port Hacking (34°S). The TEC
typically occurs in subtidal waters at depths ranging less than 1m to 10 m on sand and silty
mud substrate.
4.2.2.2
Macroalgae
Macroalgae along the southwestern and southern Australian coasts are diverse, with 62%
reported as endemic to the south coast (DEWR, 2006). They are generally limited to growing
on intertidal and subtidal rocky substrata (generally shallow waters up to 10 m depth), but
also float on the ocean surface when they become unattached.
Cold temperate macroalgae species dominate the GAB, with the distribution of tropical
species being patchy and limited to sheltered bays and other habitats where water
temperatures are warmer than the open ocean (DEWR, 2006). The canopy layers of the
southern coast are dominated by brown algae, with Ecklonia radiata (a brown algae) forming
a large proportion of the biomass. Ecklonia is common on exposed oceanic shores of SA
(DEWR, 2006). Cystophora species are abundant in higher energy environments of the SA
coast, while Sargassum species (brown algae) is more dominant in areas of reduced water
movement (DEWR, 2006).
The ‘Giant Kelp Marine Forests of South East Australia’ is listed as an ‘endangered’ TEC, and
is protected under the EPBC Act. Giant kelp (Macrocystis pyrifera) is a large brown algae
that grows on rocky reefs and is the foundation of this TEC. The TEC is defined as ‘giant
kelp growing typically at depths greater than 8 m below sea level and forming a closed or
semi-closed surface or sub-surface canopy’ (DoE, 2012). The kelp species itself is not
protected. The largest extent of this TEC is in Tasmanian coastal waters; however some
patches may also be found in Victoria and southeast SA (DSEWPC, 2012f).
4.2.2.3
Coral
Some coral species are known to occur in the GAB, including three reef-building species in
shallow waters and more than 50 non-reef-building species in waters up to 900 m deep from
the phylum Cnidaria (DEH, 2005c). Reef-forming stony corals from the phylum Bryozoa have
been collected from seamounts in the western GAB. A shallow reef extensively covered by
coral has also been identified at the Kent Group Marine Protected Area near Flinders Island
off the north-east of Tasmania.
4.2.2.4
Benthic Invertebrates
DSEWPC (2012a) reports that benthic invertebrate communities inhabiting the eastern shelf
of the GAB, particularly the inner shelf (i.e., northeast of the well locations), have been
identified as one of the world’s most diverse soft sediment ecosystems (798 species have
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been identified so far, including 360 species of sponges, 138 ascidians [sea squirts] and 93
bryozoans [lace corals]). The species that make up these communities decrease in
abundance moving away from the coast. On the inner shelf of the more eastern parts of the
GAB Shelf Transition bioregion, marine plant communities are more diverse, particularly in
the lee of islands in the Nuyts Archipelago, where significant beds of seagrass are found
(DEWHA, 2007).
Currie et al (2008) note that vast expanses of bare sand dominate the bedforms in the
Benthic Protection Zone of the former GAB Marine Park (now Multiple Use and Special
Purpose zones within the GAB CMR), comprising between 93% and 99% of the seafloor
cover at each of the seven sites within the park re-surveyed in 2006 (as follow up to a 2002
quantitative survey undertaken by SARDI Aquatic Sciences). While epifauna may be absent
from these areas of bare sand, it is known that a high diversity of infauna organisms (fauna
living between sand grains in the top few centimetres of the seabed) exists (Currie et al.,
2008), including polychaete worms, bivalves, amphipods and decapods (Rogers et al., 2013).
Sampling of infauna undertaken in 2013 as part of the GAB Research Program has found
that the total species richness is not correlated with depth, though species composition
changes were partially explained by changes in depth (Williams, 2015). The survey identified
128 distinct species across 72 families in eight major taxonomic groups. Roughly half of all
confidently identifiable species were new to science and suggest a new and endemic fauna
in the region. However, the large number of new species uncovered was unsurprising, given
there have been relatively few surveys of deep-water infauna in Australia. It was noted that
the proportion of undescribed species in the deep waters of the GAB was consistent with
data from similar depths along the WA shelf (Poore et al., 2014); suggesting these species
may be abundant and wide-spread throughout similar depth environments of the GAB.
The overall structure of the macrofaunal assemblage was largely consistent with previous
deep-water sampling from Australia (Poore et al., 2014), with composition and diversity
dominated by large numbers of polychaetes and infaunal crustaceans, but generally low
abundance. Invertebrate fauna comprises predominantly Crustacea and Annelida.
4.2.2.5
Shorebirds and Seabirds
There are 104 listed marine bird species or species habitat, plus two listed threatened
species (i.e. not specifically listed as a ‘marine bird’) that may potentially occur within the
AMBA. Thirty-four of these species are classified as threatened species, five of which are
listed as ‘critically endangered’. Sixty-four of the species are also identified as being
migratory (28 marine, 36 wetland). Twenty-seven species also have BIAs that intersect with
the AMBA.
a.
Albatross
The 17 threatened and migratory albatross species listed as potentially occurring within the
AMBA have a widespread distribution throughout the southern hemisphere. Albatrosses
nest on isolated islands and forage across the ocean for food, usually in offshore areas
during winter, and particularly along the continental shelf edge and open waters (DSEWPC,
2012e). All the listed albatross species are known to forage in Australian waters, with
cephalopods, fish and crustaceans forming the basis of their diet, caught by diving
(DSEWPC, 2012e). The National Conservation Values Atlas (DoE, 2015g) indicates that BIAs
for a number of albatross species intersect with the AMBA. No breeding colonies or nesting
areas for the listed albatross species are located within the vicinity of the well locations, or
AMBA (DSEWPC, 2012e).
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b.
Petrels
The eight threatened and migratory petrel species listed as potentially occurring within the
AMBA are widely distributed throughout the southern hemisphere. They nest on isolated
islands and typically breed on sub-Antarctic and Antarctic islands (i.e. outside of the AMBA).
DSEWPC (2012e) reports that the Great-winged petrel (Pterodroma macroptera) is the only
one that breeds in the South-west Marine Region, with an estimated 33,000 breeding pairs
on the islands of the Recherche Archipelago. The National Conservation Values Atlas (DoE,
2015g) indicates that BIAs for a number of petrel species intersect with the AMBA, but are
unlikely to be encountered in the vicinity of the well locations.
c.
Shearwaters
There are six shearwater species (of which five are migratory) listed as potentially occurring
within the AMBA. Shearwaters are oceanic species that may occur along throughout the
AMBA, but generally only during the breeding season, where they favour remote islands or
headlands (Flegg, 2002). Shearwaters are known to forage for krill, fish and squid. The
National Conservation Values Atlas (DoE, 2015g) indicates that BIAs for a number of
shearwater species intersect with the AMBA. The short-tailed shearwater foraging BIA is
the only one to intersect with the well locations.
d.
Terns
There are eight tern species (of which one is threatened, and four migratory) listed as
potentially occurring within the AMBA. Many of the tern species are widespread and occupy
beach, wetland, grassland and beach habitats. Terns rarely swim; they hunt for prey in flight,
dipping to the water surface or plunge-diving for prey (Flegg, 2002) usually within sight of
land, for fish, squid, jellyfish and sometimes crustaceans (DEHWA, 2007). The National
Conservation Values Atlas (DoE, 2015g) indicates that BIAs for a number of tern species
intersect with the AMBA; none intersect with the well locations.
e.
Gulls
The Pacific, Silver, and Kelp gulls are known to breed within the AMBA. Silver gulls breed on
many islands throughout the AMBA, however larger colonies nest adjacent to urban areas
(DEWR, 2006). Pacific gulls remain the dominant large gull throughout the South-west
Marine Region, breeding in small numbers (usually 1-2 pairs/island), with strongholds at the
Recherche Archipelago and The Brothers Islands in Coffin Bay (DEWR, 2006). The National
Conservation Values Atlas (DoE, 2015g) indicates that a BIA exists within the AMBA for the
Pacific gull (Larus pacificus).
f.
Australasian Gannet
The Australasian gannet (Morus serrator) generally feeds over the continental shelf or
inshore waters. Its diet is comprised mainly of pelagic fish, and prey is caught mainly by
plunge-diving, but it is also seen regularly attending trawlers. Breeding is highly seasonal
(October–May), nesting on the ground in small but dense colonies (DoE, 2015a). The Southeast Marine Region supports breeding sites for approximately 20% of the global population
and all of the Australian breeding population (DoE, 2015a). The National Conservation Values
Atlas (DoE, 2015g) indicates that a BIA intersects with the AMBA for this species.
g.
Black-faced Cormorant
The Black-faced cormorant (Phalocrocorax fuscescens) is endemic to southern Australia
(DoE, 2015a). Flegg (2002) states that this species is confined to the southeastern and
southwestern seaboards, where it favours rocky coast, is sedentary and locally common.
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This species feeds in coastal waters, sometimes in sheltered places such as bays and islets
and can be found entering rivers along the coast. Its diet is comprised of a variety of fish
which it catches mainly by pursuit-diving, sometimes in flocks of up to several thousand
individuals. There are 40 significant breeding sites (more than 10 breeding pairs) known for
the species, recognised as BIAs. Breeding usually occurs on rocky islands, but also on
stacks, slopes and sea cliffs in colonies of up to 2500 individuals (DoE, 2015a).
h.
Little Penguin
Little penguins (Eudyptula minor) are the smallest species of penguin in the world and are
permanent residents on a number of inshore and offshore islands. The Australian population
is large but not thought to exceed 1 million birds (DoE, 2015a). Bass Strait has the largest
proportion (ca. 60%) of the known breeding colonies in Australia; but breeding is also known
to occur in SA (e.g. Pearson Island holds largest breeding population in SA), and in WA (e.g.
at Recherche Archipelago). Individuals exhibit strong site fidelity, returning to the same
breeding colony each year to breed in the winter and spring months (Gillanders et al., 2013).
The National Conservation Values Atlas (DoE, 2015g) indicates that a BIAs for foraging and
breeding exist within the AMBA for the Little Penguin.
4.2.2.6
Marine Reptiles
Six species of marine reptile are listed under the EPBC Act as potentially occurring in the
AMBA:
•
Loggerhead turtle
•
Green turtle
•
Leatherback turtle
•
Hawksbill turtle
•
Flatback turtle
•
Yellow-bellied seasnake
All five marine turtle species are classified as ‘threatened’ and ‘migratory’; however, there is
no defined BIA (foraging, inter-nesting, or nesting) for any of these turtle species within the
AMBA.
4.2.2.7
a.
Plankton
Phytoplankton
Phytoplankton (photosynthetic microalgae) comprise 13 divisions of mainly microscopic
algae, including diatoms, dinoflagellates, gold-brown flagellates, green flagellates and
cyanobacteria and prochlorophytes (McLeay et al., 2003). The GAB slope and offshore
waters were sampled during the BP supported RV Southern Surveyor voyage in April 2013.
Highest concentrations of Chl a occurred at depths of 60m (0.43 ug/L) at the 200m and
400m isobaths. Chl a declined with distance from the shelf edge to low concentrations (0.19
ug/L) at stations at the 1000m and 2000m isobaths. Dinoflagellates generally dominated the
phytoplankton community (typically >40%) followed by flagellates.
b.
Zooplankton
Zooplankton is the faunal component of plankton, comprised of small crustaceans (such as
krill) and fish larvae that feed on zooplankton. Sampling during April 2013 collected a range
of crustaceans, siphonophores, jellyfish and larval fish (Williams et al., 2013). The surface
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samples showed that copepods were the dominant taxonomic group in the eastern GAB
and that copepods and Appendicularia dominate in shelf and offshore waters in the central
GAB (Kloser et al, 2015).
4.2.2.8
Fish – Demersal
Bony demersal fish are those species living on or near the seabed, and can occur in all water
depths. Inshore, these species occur in habitats ranging from estuaries, seagrass beds, reef
and muddy and sandy seabeds (DEWR, 2006). Some inshore demersal fishes are
completely habitat dependent, and do not move away from their “home” reef, seagrass bed
or sand patch.
Examples of demersal fish taxa include:
•
Inshore: King George whiting (Sillaginodes punctatus), pink snapper (Pagrus auratus),
ocean leatherjacket (Nelusetta ayraudi), spangled emperor (Lethrinus nebulosus),
western smooth boxfish (Anoplocapros amygdaloides), rock ling (Genypterus tigerinus)
•
Continental shelf: Labridae (wrasses), Syngnathidae (seahorses, pipe fish), Gobiesocidae
(clingfishes), Gobiidae (gobies), Clinidae (weedfish) and Monocanthidae (leatherjacket,
puffer fish). Deeper waters are dominated by the Moridae (cods, moras), Antennariidae
(frogfish), Macrouridae (grenadiers), Scorpaenidae (scorpion fish, lion fish) and
Trachichthyidae (roughy) families
•
Continental slope: Macrouridae (whiptails), Squalidae (dogfish sharks), Alepocephalidae
(slickheads), Ophidiidae (ling), Moridae, Triglidae (gunard), Scyliorhinidae (carsharks) and
Scorpaenidae.
4.2.2.9
Fish – Pelagic
There are 61 fish species (48 of which are syngnathids) recorded under the EPBC Act as
potentially occurring within the AMBA. Two shark species, grey nurse and great white, also
have BIAs that intersect with the AMBA.
McLeay et al (2003) report that three quarters of the 3,400 marine fish species in Australian
waters occur on the shelf and in nearshore waters, with about 85% of southern Australia’s
fishes being endemic to the region. Many of the fish species in the GAB are inshore
inhabitants with permanent resident populations. However, there are also some regular
migratory visitors such as the Australian salmon (Arripis truttaceus) and occasional oceanic
vagrants such as oceanic sunfish (Mola sp.), basking shark (Cetorhinus maximus), black
marlin (Makaira indica), and the lizardfish (Saurida undosquamis) (DEH, 2005c). In deeper
waters ranging from 400-1,200 m, surveys have recorded 166 species of deep-sea fish
(DEH, 2005c).
a.
Grey nurse shark
The grey nurse shark (Carcharias taurus), listed as a ‘vulnerable’ species under the EPBC
Act, has a broad inshore distribution, primarily in sub-tropical to cool temperate waters
(DSEWPC, 2012b; DoE, 2014b). The west coast population of the species is predominantly
found in the southwest coastal waters of WA (east to Cocklebiddy and north to the North
West Shelf), preferring water depths from the surf zone down to 190 m (DoE, 2014a). The
Grey Nurse Shark (east coast population) has been regularly reported from southern
Queensland and around south-east Australia, although the species is uncommon in Victorian,
South Australian and Tasmanian waters, and has not been found in the GAB. A distribution
BIA has extends along the NSW coast (and therefore intersecting the AMBA) for this
species.
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b.
Great white shark
The great white shark (Carcharodon carcharias), listed as a ‘vulnerable’ and ‘migratory’
species under the EPBC Act, is widely but sparsely distributed throughout temperate and
sub-tropical regions of the world (Norman, 2005; Bruce et al., 2005). It is primarily found in
the coastal and offshore areas of the continental and insular shelves and offshore
continental islands (Cavanagh et al., 2003; Bruce et al., 2005; DSEWPC, 2013a). The
Neptune Islands, Dangerous Reef, Fowlers Bay and the Pages (near Kangaroo Island) are
areas of known great white shark encounters (DEWHA, 2007; Cavanaugh et al., 2003), with
sharks present throughout the year. The greatest numbers are observed during winter to
spring when females are more prevalent (Rogers et al., 2013).
In the GAB, great white sharks are recorded from close inshore rocky reefs, surf beaches
and shallow coastal bays to the outer continental shelf and slope (Rogers et al., 2013), with
the drilling area being 133 km south of the nearest BIA (foraging) for the species.
c.
Conservation-dependent fish species
In addition to the threatened species listed under the EPBC Act Protected Matters Report,
all seven of the ‘conservation-dependent’ fish species listed under the EPBC Act are known
to occur in the AMBA. These are:
•
Harrisson’s dogfish (Centrophorus harrissoni)
•
Southern dogfish (Centrophorus zeehaani)
•
School shark (Galeorhinus galeus)
•
Orange roughy (Hoplostethus atlanticus)
•
Eastern gemfish (Rexea solandri) (eastern Australian population)
•
Blue warehou (Seriolla brama); and
•
Southern bluefin tuna (SBT) (Thunnus maccoyii).
Note that these species are listed as ‘conservation-dependent’ under the EPBC Act due to
overfishing (DSEWPC, 2012a).
4.2.2.10 Marine Mammals – Pinnipeds
There are five pinniped species recorded under the EPBC Act as potentially occurring within
the AMBA:
•
New Zealand fur-seal
•
Australian fur-seal
•
Dugong
•
Southern elephant seal
•
Australian sea lion
The Australian sea lion also has a BIA intersecting with the AMBA. The distribution of the
species extends from the Houtman Abrolhos Islands on the WA west coast through the
Pages Islands to the east of Kangaroo Island in SA (DSEWPC, 2013b). The species generally
hauls out (rests) and breeds on rocks and sandy beaches on sheltered sides of islands,
although some small colonies exist on the mainland. Only eight sites produce >100 pups per
season: North and South Page Islands, Seal Bay on Kangaroo Island, Dangerous Reef
(supports the third-largest breeding population in the world), Lewis Island, West Waldegrave
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Island, Olive Island and Purdie Island (DSEWPC, 2012g, Rogers et al., 2013; Edyvane, 1999).
All eight of these large breeding colonies are within the AMBA.
Female Australian sea lions travel up to 130 km on foraging trips and dive to depths of 130
m, while males travel up to 300 km and dive to at least 200 m (Rogers et al., 2013). This
species is unlikely to be encountered in the vicinity of the well locations, but may occur
within the AMBA. No Australian sea lions were observed during the 2011-12 Ceduna 3D
seismic survey.
4.2.2.11 Marine Mammals – Cetaceans
There are 29 whale species and 12 dolphin species recorded under the EPBC Act as
potentially occurring within the AMBA; four of these also have BIAs intersecting with the
AMBA:
•
Blue whale
•
Southern right whale
•
Humpback whale
•
Sperm whale.
a.
Blue whale
There are two recognized subspecies of blue whale in Australian waters; the Antarctic blue
whale and the pygmy blue whale (DSEWPC, 2012c). Both subspecies are found in all
Australian waters, with the Antarctic blue whale primarily found in waters south of 60°S and
pygmy blues found in waters north of 55°S (DSEWPC, 2012c). Both species feed on krill,
with the nearest foraging BIA located approximately 20 km north of the Winham-1 well
location, and along the shelf break to the west and south of Kangaroo Island, extending
northwest along the 200 m isobaths (Morrice et al., 2004; DEWHA, 2007; DSEWPC, 2012c).
During the 2011-12 Ceduna 3D seismic survey, a total of 12 blue whales were observed; 10
within the vicinity of the well locations and two during transit. Ten of these sightings
occurred during November. Pygmy blue whales were also detected at the Head of Bight by
sound loggers deployed from November 2011 to June 2012, with no detection of pygmy
blue whales from late January to May 2012 at the Head of Bight (McCauley et al., 2012). An
offshore aerial cetacean survey (between 100 m and 200 m depth contours) was undertaken
between southwest Kangaroo Island to south of the Head of the Bight, during December
2015 and April 2016 (Gill, P; 2016); this survey recorded six Blue (most likely pygmy) whales.
b.
Southern right whale
The Southern right whale (SRW) (Eubalaena australis), listed as ‘endangered’ and ‘migratory’
under the EPBC Act, is typically distributed between 20°S and 60°S in the southern
hemisphere and is present off the Australian coast between May and November (primarily
southwest WA and far west SA). The National Conservation Values Atlas recognizes a BIA
for the SRW approximately 230 km north of the well locations.
The closest aggregation area to the well locations is the Head of Bight, approximately
270 km to the north. This is a significant aggregation area, where up to half the population
gathers between May and November to calve (DEH, 2006; DEWHA, 2007), usually in waters
less than 10 m (DSEWPC, 2012d) to 20 m deep (Charlton et al., 2014). Twilight Bay, Fowlers
Bay and Encounter Bay are other known calving areas in the region (DEWHA, 2007). Female-
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calf pairs generally stay within the calving grounds for 2-3 months (DSEWPC, 2012d),
peaking from mid to late July to mid-late August at the Head of Bight.
Aerial surveys for inshore cetaceans undertaken across coastal waters (<100 m water
depth) of the GAB between Ceduna and Coffin Bay during July and August 2013 detected
seven SRW (Bilgmann et al., 2014). No SRW were observed in the vicinity of the well
locations during the Ceduna 3D seismic survey undertaken between November 2011 and
May 2012.
c.
Humpback whale
The humpback whale (Megaptera novaeangliae), listed as ‘vulnerable’ and ‘migratory’ under
the EPBC Act, has a worldwide distribution. Humpback whales are found in Australian
offshore and Antarctic waters. They primarily feed on krill in Antarctic waters south of 55°S.
The nearest known humpback whale resting area is in Flinders Bay on the south coast of
WA, approximately 1,400 km west of the well locations. Humpback whales undertake
annual migrations between their summer feeding grounds in Antarctic waters to their
breeding and calving grounds in sub-tropical and tropical inshore waters (Jenner et al., 2001).
Humpback whales migrate up the eastern and western coasts of Australia and do not often
travel into the GAB (DEH, 2005b; Vang, 2002). The northern migration of the southeast coast
starts in April and May, while on the west coast, it occurs towards early June. The west
coast southern migration then peaks around November and December, while the east coast
southern migration peaks in October and November.
Small numbers of humpback whales have been observed at the Head of Bight and near
Kangaroo Island in early winter. Aerial surveys for inshore cetaceans undertaken across
coastal waters (<100 m water depth) of the GAB between Ceduna and Coffin Bay during
July and August 2013 detected three humpback whales (Bilgmann et al., 2014). No
humpback whales were observed during the 2011-12 Ceduna 3D seismic survey nor were
they detected by sound loggers deployed from November 2011 to June 2012 at three
locations in the GAB (McCauley et al., 2012).
d.
Sperm Whale
Sperm whales (Physeter macrocephalus), listed as migratory under the EPBC Act, are found
in waters from the Arctic to the tropics, usually in deep offshore waters. Male sperm whales
are found in higher latitudes and migrate towards lower latitudes for mating during the
summer months. Females, calves and juveniles remain in the warmer tropical and subtropical waters of the Indian Ocean all year round (DEWHA, 2007). Females and juveniles
appear to move between the eastern Indian Ocean and Tasman Sea down to 55°S while
mature males migrate seasonally between Antarctic waters and equatorial breeding
grounds.
DSWEPC (2012) indicates that in the South-west Marine Region, a BIA for sperm whale
foraging is concentrated along the shelf break of the GAB and waters south of Kangaroo
Island. The BIA overlaps with the Whinham-1 well location.
During the 2011-12 Ceduna 3D seismic survey, a total of 25 sperm whales were observed
during December, April and May. No sperm whale sound signals were detected by sound
loggers deployed from November 2011 to June 2012 at three locations in the GAB
(McCauley et al., 2012). An offshore aerial cetacean survey (between 100 m and 200 m
depth contours) was undertaken between southwest Kangaroo Island to south of the Head
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of the Bight, during December 2015 and April 2016 (Gill, P; 2016); this survey recorded three
sperm whales.
4.3
Social Values
4.3.1
Marine Bioregions
The AMBA intersects three marine bioregions: south-west, south-east and temperate east.
Fifteen of the key ecological features identified within these marine bioregions intersect
with the AMBA (Figure 2):
•
Albany Canyons group and adjacent shelf break
•
The Diamantina Fracture Zone
•
Commonwealth Marine Environment surrounding the Recherche Archipelago
•
Ancient coastline at 90–120 m depth
•
Kangaroo Island Pool, canyons and adjacent shelf break, and Eyre Peninsula upwellings
•
Small pelagic fish
•
Benthic invertebrate communities of the eastern GAB
•
Bonney Coast Upwelling
•
East Tasmania subtropical convergence zone
•
Bass Cascade
•
Upwelling east of Eden
•
Big Horseshoe Canyon
•
West Tasmania Canyons
•
Seamounts south and east of Tasmania
•
Shelf rocky reefs and hard substrates
•
Shelf rocky reefs
•
Canyons on the eastern continental slope
•
Tasman front and eddy field
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Note that the following KEFS: ‘Small pelagic fish’, ‘Benthic invertebrate communities of the
GAB’, ‘East Tasmania subtropical convergence zone’, ‘Bass Cascade’, and ‘Shelf rocky reefs
and hard substrates’, are not spatially defined.
Figure 2: Key Ecological Features present within the AMBA
4.3.2
Offshore Protected Areas
4.3.2.1
Commonwealth Marine Reserves
The Australian Government has established numerous CMRs around Australia under the
EPBC Act; 23 of which occur within the AMBA (Figure 3).
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Figure 3: CMRs within the AMBA
Both Stromlo-1 and Whinham-1 wells are located within the GAB CMR. The GAB CMR was
originally declared in 1998, and extended in November 2012, encompassing the former GAB
Marine Park (GABMP) (Commonwealth waters). A management plan for the new
Commonwealth marine reserves declared for the southwest Australian region is not yet
available, due to the CMR Review. However, the Draft South-west Commonwealth Marine
Reserves Network Management Plan 2014-24 (Director of National Parks, 2013) was
released in 2013 and information from this plan, and the superseded GAB Marine Park
Management Plan (2005-12) (DEH, 2005a), has been used in this EP in the absence of a final
plan for the reserve.
The ‘major conservation values’ identified for the GAB CMR (Director of National Parks,
2013) are:
•
Important foraging areas for the threatened Australian sea lion and great white shark
•
Important foraging areas for the migratory sperm whale and short-tailed shearwater;
•
Provision of globally important seasonal calving habitat for the SRW;
•
Examples of central and western ecosystems of the GAB Shelf Transition and the
eastern-most ecosystems of the Southern Province;
•
Presence of three KEFs:
−
Ancient coastline 90-120 m (high productivity zone).
−
Benthic invertebrate communities of the eastern GAB (high species diversity).
−
Areas important for pelagic fish.
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4.3.2.2
State Marine Parks and Reserves
There are numerous state marine parks or reserves within WA (1), SA (19), Victoria (30),
NSW (13) and Tasmania (6) that intersect with the AMBA. All of the state marine parks and
reserves boundaries are distant to the well locations.
4.3.3
Onshore Protected Areas
4.3.3.1
Wetlands of International Importance
There are eleven Ramsar wetlands that have coastal boundaries intersecting the AMBA:
•
Corner Inlet
•
East coast cape barren island lagoons
•
Flood Plain Lower Ringarooma River
•
Gippsland Lakes
•
Lake Gore
•
Lavinia
•
Logan Lagoon
•
Piccaninnie Ponds Karst Wetlands
•
Port Phillip Bay (Western Shoreline) and Bellarine Peninsula
•
The Coorong, and lakes Alexandrina and Albert wetland
•
Western Port
The closest wetland to the drilling location is the Coorong, and lakes Alexandrina and Albert
wetland.
4.3.3.2
Wetlands of National Importance
There are 59 ‘marine and coastal zone’ nationally important wetlands within the AMBA (11 in
SA, 43 in Tasmania, and 5 in NSW).
4.3.3.3
Parks and Reserves
Numerous onshore protected areas (e.g., National Parks, Nature Reserves, Conservation
Parks, Conservation Reserves, Wilderness Protection Areas and Aquatic Reserves) occur
along the coast of the AMBA. Although located wholly or partly on the coast, these parks are
terrestrial by nature, usually extending to the high or low water mark of the reserve.
4.3.4
Coastal Settlements
At its nearest point, the well locations are located approximately 260 km south of the
Australian mainland. This part of the mainland is dominated by the Nullarbor Plain, with very
few populated settlements. The economy of this stretch of the Nullarbor Plain is based
largely on sheep grazing of native Acacia, mallee woodlands, bluebush and saltbush, and the
supply of accommodation (motel, caravan and camping), fuel and other services to highway
travellers. Much of the Nullarbor remains undeveloped; pastoral leaseholds for sheep grazing
cover about one-third of the region, mainly near the coast of WA, but pastoralism is limited
by lack of bore water.
Ceduna and Port Lincoln are the largest towns in the region. Ceduna’s economy is centred
on crop and sheep farming, tourism, fishing and port activities that ship salt, gypsum and
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heavy mineral concentrate from mines located to its north (the Thevenard Port is located 3
km east of the town). Aquaculture (oyster farming) in Denial Bay and Smoky Bay are also
important industries for the area (District Council of Ceduna, 2012). Port Lincoln is well
regarded for its tuna fishing. Like Ceduna, its economy is based on crop, sheep and beef
farming, as well as tuna, prawn, abalone and scale fishing and shark cage diving).
4.3.5
Commercial Fishing and Aquaculture
4.3.5.1
Commonwealth-managed Fisheries
Commonwealth fisheries are managed by AFMA, with fisheries operating within
approximately 3 nm to 200 nm offshore (the extent of the Australian Fishing Zone, AFZ).
There are eight commercial fisheries that intersect with the AMBA:
•
Bass Strait Central Zone Scallop
•
Eastern Tuna and Billfish Fishery
•
Skipjack Tuna Fishery
•
Small Pelagic Fishery
•
Southern and Easter Scalefish and Shark Fishery
•
Southern Bluefin Tuna Fishery
•
Southern Squid Jig Fishery
•
Western Tuna and Billfish Fishery
With the exception of the Bass Strait Central Zone Scallop, and Eastern Tuna and Billfish
Fisheries, all these also intersect with the well locations.
The value of production of Commonwealth fisheries was $320 million in 2010-11,
contributing 14% of the gross value of Australia’s total fisheries production (AFMA, 2014).
4.3.5.2
State-managed Fisheries
A number of state managed fisheries occur in WA and SA, and intersect with the AMBA.
State-managed fisheries in SA are managed by PIRSA under the Fisheries Management Act
2007 (SA), associated regulations and management plans. PIRSA reports that the 10 wildcatch commercial fisheries contribute $197 million to SA’s total seafood production value
(EconSearch, 2014). In WA, state-managed fisheries are managed by the Department of
Fisheries (DoF) under the Fish Resources Management Act 1994 (WA), associated
regulations and management plans. In 2010, commercial fishing (including pearling and
aquaculture) contributed an estimated $818 million to the WA economy (DoF, 2012). All of
these state-managed fisheries are restricted to shallow waters along the coast that do not
occur near the well locations.
In addition, Victoria, Tasmania and NSW have various state managed fisheries which
intersect the AMBA although at a much lesser probability and exposure level.
4.3.6
Recreational Fishing
The majority of recreational fishing in the GAB (and elsewhere along the southern coastline
of Australia) is based around the coast and shallow waters, using line fishing methods from
the beach and from vessels, with the most commonly captured species including whiting
(Sillaginidae), trevally (Pseudocaranx spp.), black bream, and WA salmon. Recreational
abalone diving on the WA south coast is popular, as is shark fishing (Fletcher and Santoro,
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2013). There is no recreational fishing known to occur in the vicinity of the well locations
given their distance offshore.
4.3.7
Commercial Shipping
Shipping activity in the vicinity of the well locations is relatively low, with the main shipping
route located to the south of the well locations. Smaller numbers of vessels travel between
Thevenard Port to the west and south towards Port Lincoln and Victoria; these vessels may
pass through in the vicinity of the well locations.
4.3.8
Tourism and Recreation
There are no tourism or recreation activities recorded within the vicinity of the well locations.
Tourism activities associated with the coastal regions are varied and include: marine
mammal watching, shark cage diving, fishing, camping and surfing.
4.3.9
Cultural Heritage
4.3.9.1
Listed Heritage Places
There are no World Heritage, or Commonwealth Heritage places located within or
immediately adjacent to the coast of the AMBA (DoE, 2015b; DoE, 2015c). There are four
‘historic’ National Heritage listed places (DoE 2015d):
•
Bondi Beach (NSW)
•
Kurnell Peninsula Headland (NSW)
•
North Head (NSW)
•
Recherche Bay (North East Peninsula) Area (TAS)
4.3.9.2
Aboriginal Heritage
Many Aboriginal and Torres Strait Islander peoples have a close, long-standing relationship
with coastal and marine environments and continue to rely on these environments and
resources for their cultural identity, health and wellbeing, as well as their domestic and
commercial economies (DSEWPC, 2012a).
Native Title claimant applications cover large areas of Australia coast (including some state
waters), and are therefore intersected by the AMBA. None of the claimant applications that
extend into state waters have been determined yet. No Native Title claims extend into
Commonwealth waters (NNTT, 2015).
4.3.9.3
Shipwrecks
The Australian Shipwreck Database (DoE, 2015e) lists numerous historic shipwrecks
occurring within the AMBA, though the majority of these are located inshore of the mainland
or outlying islands. For example, there are 19 ships’ graveyards located in SA waters, all of
these located within the two gulfs, except for one at Goat Island near Ceduna (the Eleni K in
11-13 m of water) and two on the southeast tip of Kangaroo Island, these being the Pam and
Quorna that lie in 50 m of water (DEWNR, 2015).
Shipwrecks in Commonwealth waters that are 75 years or older are protected under the
Historic Shipwrecks Act 1976 (Cth). There are only a small number of historic shipwrecks
located in Commonwealth waters, with none around the well locations, but some (5) are
recorded within the AMBA (DoE, 2015f).
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4.3.10
Petroleum Exploration and Production
Ten exploration permits exist within the GAB, and one exploration permit was released by
the Commonwealth Government for bidding in the 2015 acreage release.
4.3.11
Defence Activities
The Commonwealth Department of Defence training areas do not extend into any offshore
waters of the GAB. The closest training areas to the well locations are in Investigator Strait
(a body of water lying between the Yorke Peninsula and Kangaroo Island) used for military
flying and firing, and waters off Port Lincoln used for firing and naval operations (DEWHA,
2007).
5
Environmental Impact and Risk Assessment
BP manages, monitors and reports on the principal risks and uncertainties that can impact
our ability to deliver our strategy of meeting the world’s energy needs responsibly, while
creating long term shareholder value. Our management systems, organizational structures,
processes, standards, code of conduct and behaviours together form a system of internal
control that governs how we conduct the business of BP and manage associated risks.
The risk assessment methodology applied during development of this EP allows for the
identification of potential impacts from planned activities, as well as the risk and
consequences of unplanned events. The purpose of risk assessment is to assist in making
decisions, based on the outcomes of analysis, about the sorts of control measures required
to reduce an impact or risk to ‘As Low As Reasonably Practicable’ (ALARP) and to
acceptable levels. Planned and unplanned events are subject to this step in the same
manner. The environmental risk assessment also outlines the controls, performance
outcomes, performance standards and measurement criteria required to address the
impacts and risks identified.
The process by which the project identified and assessed impacts and risks associated with
the project included the following steps:
•
Definition of activity;
•
Identification of potential impacts and risks;
•
Assessment of severity/consequence of these potential impacts and risks;
•
Identification of additional controls (ALARP decision context);
•
Determination of likelihood of consequence (with additional controls);
•
Determination of risk significance (which is a combination of severity/consequence and
likelihood); and
•
Identification of mitigation and management measures.
The potential impacts and risks associated with the petroleum activity are summarised in
Table 4. Potential impacts and risks associated with accidental releases are addressed in
Section 6, and potential impacts and risks associated with oil spill response activities are
addressed in Section 7.
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Table 4 - Environmental risk assessment summary
Hazard
Known and Potential Impacts
Key mitigation and management measures
Risk
Conseqence
Likelihood
• The support vessels will implement the Australian
Guidelines for Whale and Dolphin Watching (2005) for
sea-faring activities while in the PSZ.
• Vessel masters briefed on caution and ‘no approach
zones’.
• Any collisions with cetaceans will be reported to the
DoE.
Undetectable
Unlikely /
Not
or limited
infrequent
Significant
• Exclusion of commercial
vessels to areas around the
well location.
• Damage to fishing
equipment.
• Loss of commercial fish
catches.
• Sailing Plan / Notice to Mariners provided to
government agencies.
• BP ongoing stakeholder consultation.
Undetectable
Unlikely /
Not
or limited
infrequent
Significant
Introduction of a
marine pest
• Impacts to seabed habitat
and marine ecosystems due
to out competing native
species.
• The MODU and support vessels will be cleared to enter
Australian waters by the Australian Quarantine
Inspection Service (AQIS).
• Ballast water management plan and ballast water record
book will be in place and maintained.
• The MODU and support vessels will possess valid
International Anti-fouling System Certificates.
Seabed
disturbance
• Smothering and alteration of
benthic habitat.
• Localised and temporary
increase in turbidity near the
seabed.
• Transponders and weights will be retrieved at the
completion of drilling each well.
significance
Petroleum Activity
Collision with
cetaceans
Interference with
other marine
users
• Cetacean injury or death
caused by vessel strike.
degradation
local
degradation
Moderate
Unlikely /
Not
degradation
infrequent
Significant
Undetectable
Moderate
Minor
or limited
probability
Significance
local
/ frequency
degradation
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Hazard
Underwater
sound
Light emissions
Atmospheric
Known and Potential Impacts
Key mitigation and management measures
• Localised and temporary
behavioural disturbance.
• Auditory impairment,
Permanent Threshold Shift
(PTS).
• Mortality.
• Vertical seismic profiling (VSP) crew aboard the MODU
will be inducted into the EPBC Act Policy 2.1.
• VSP operations will be conducted in accordance with
Part A - EPBC Act Policy 2.1.
• Several controls from Part B - EPBC Act Policy 2.1 will
be implemented, specifically:
o
increased ‘low power zone’ of 2km will be
implemented for Whinham-1 during VSP.
o
a PAM detection sensitivity study will be
undertaken prior to VSP being conducted to
determine the value of using PAM deployed
from MODU.
• MMOs will have access to infra-red binoculars to assist
observations during VSP activities conducted during
periods of low visibility
• Cetaceans sighted during VSP will be reported to the
DoE.
• MODU and support vessel engines and thrusters will be
maintained as per planned maintenance system (PMS)
to ensure they are operating efficiently.
• A sound measurement study will be conducted to verify
the outcomes of the sound modelling study. Should the
results of the sound measurement study suggest
significantly higher sound levels than those predicted by
the modelling, sound modelling will be repeated and
basic sound level threshold analysis will be undertaken.
Temporary and localised
attraction of light-sensitive
species, in turn affecting
predator-prey dynamics.
• Ensure the MODU and vessels are lit in accordance
with maritime safety standards.
• Chronic effects to sensitive
receptors from localised and
• Only low-sulphur marine diesel oil will be used
• Fuel use will be measured, recorded and reported.
Likelihood
Risk
significance
Moderate
Moderate
Minor
degradation
probability
Significance
/ frequency
Undetectable
High
Minor
or limited
probability
Significance
High
Minor
local
degradation
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Hazard
Risk
Key mitigation and management measures
Conseqence
Likelihood
temporary decrease in air
quality from diesel
combustion.
• Contribution to global
Greenhouse Gas (GHG)
effect.
• The MODU and support vessels will maintain a current
International Air Pollution Prevention (IAPP) Certificate
in accordance with MARPOL Annex VI, which certifies
that measures to prevent ozone-depleting substance
(ODS) emissions, and to reduce NOx, SOx and
incineration emissions during the activity are in place
• Combustion equipment on the MODU and support
vessels will be maintained in accordance with the PMS
to ensure they are operations to design specifications.
• The MODU Heating, Venting and Air Conditioning
system will be maintained in accordance with the PMS
to prevent refrigerant gas leaks.
or limited
probability
Significance
Discharge of
drilling cuttings
and fluids
• Increased turbidity of the
water column.
• Increased turbidity near the
seabed (from resuspension).
• Smothering of seabed
habitat and fauna resulting in
the alteration of seabed
substrate.
• Potential chemical toxicity
and oxygen depletion
impacts to fauna in the
water column and sediment.
• All drill fluids evaluated in accordance with BP’s
Chemical Assessment Guideline and accepted prior to
use.
• Solids control equipment (shale shakers and centrifuge)
will treat cuttings to a level of <6.9% ROC.
• Drilling Fluid and Waste Management Program ensures
volumes of SBM mixed align with program
requirements, and fluids discharged overboard from
mud tank cleaning will contain <1% by volume of oil in
the fluid sample (<1% v/v).
• Pre Spud and Post Drill ROV surveys will be undertaken
to identify and if possible quantify cuttings deposition
within the areas surrounding the well locations to
determine the impact to seabed habitat and fauna.
• Personnel will monitor the fluids and solids control
equipment to ensure effectiveness is maintained.
Moderate
Moderate
Minor
degradation
probability
Significance
Discharge of
cement
• Increased turbidity of the
water column.
• Smothering of benthic
habitat and fauna resulting in
the alteration of benthic
• Evaluate all cementing products and additives in
accordance with BP’s Chemical Assessment Guideline.
• Cementing Program will be developed and
implemented.
• ROV surveys will be undertaken to confirm the extent
emissions
Known and Potential Impacts
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significance
local
degradation
/ frequency
Moderate
degradation
Low
Minor
Probability
Significance
/ frequency
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Hazard
Known and Potential Impacts
substrate.
• Potential toxicity impacts to
fauna.
Discharge of
cooling and brine
water
Discharge of
sewage and grey
water and
putrescible waste
Discharge of deck
drainage and
bilge water
Discharge of BOP
Key mitigation and management measures
Risk
Conseqence
Likelihood
Undetectable
Moderate
Not
or limited
probability
Significant
local
/ frequency
significance
of impact from cementing activities.
Impacts to fauna through:
• Increased temperature.
• Increased salinity.
• Potential toxicity.
• PMS records verify that the RO plant and cooling
system are maintained to schedule
• Changes to the water quality
through nutrient enrichment
and increased biological
oxygen demand.
• Impact to predator / prey
dynamics.
• A MARPOL-approved sewage treatment plant (STP) will
be fitted to the MODU and support vessels.
• The STPs will be maintained in accordance with the
PMS to ensure they are not discharging untreated
sewage.
• The MODU and support vessels have a current
International Sewage Pollution Prevention (ISPP).
• All food waste is macerated to ≤25 mm in size prior to
overboard discharge in accordance with Regulation 8 of
MARPOL Annex V.
• The macerators are maintained or replaced as per the
PMS to ensure they are fully functional.
Undetectable
Moderate
Not
or limited
probability
Significant
local
/ frequency
• Acute toxicity to marine
• Bilge water will be treated through an oily water system
to remove hydrocarbons prior to overboard discharge
(discharge water will not contain > 15 ppm
hydrocarbons, in line with MARPOL Annex I).
• Maintenance of the oily water system will be conducted
in accordance with the PMS.
• Any oily wastes transferred to shore will be recorded in
the Oil Transfer Book
• SMPEP response kits are available in relevant locations,
are fully stocked and used in the event of a spill to deck
to prevent or minimise discharge overboard.
Undetectable
Low
Not
or limited
Probability
Significant
local
/ frequency
• Evaluate BOP Fluid in accordance with BP’s Chemical
Undetectable
fauna.
• Acute toxicity to marine
degradation
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Low
Not
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Hazard
Fluids
Known and Potential Impacts
fauna.
Key mitigation and management measures
Assessment Guideline.
Conseqence
Likelihood
or limited
Probability
local
/ frequency
degradation
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Significant
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6
Environmental Impact and Risk Evaluation – Accidental Release
BP uses a number of processes to identify and manage potential accidental events and uses
company procedures to define emergency response and management strategies for its
projects around the world. As part of its planning for drilling operations, the project has
identified and defined potential accidental release events, including spill planning scenarios.
Additionally, the project has identified potential response measures for the spill scenarios
which have been detailed in operational plans that will be used by the project.
This section is designed to provide an overview of BP’s approach to risk management and
emergency response, including lessons which have been learned and applied since the
DWH incident in 2010. This section also provides an overview of the potential accidental
release events that could arrive during project activities, and includes an environmental
assessment of these release events.
6.1
Risk Management within BP
The barrier philosophy, shown below, underpins BP’s approach to risk management.
Through this approach, it is possible to consider measures, or barriers, that are put in place
to prevent hazards (i.e. something which has the potential to cause harm) from materialising
into an adverse event. These are referred to as preventative barriers. Similarly, in the event
that an adverse event does occur it is necessary to consider which measures, or barriers can
be taken to minimise and mitigate any consequences. These are referred to mitigative
barriers. Multiple mitigative and preventative barriers are put in place for each potential
incident which could occur. Throughout the project planning and execution, the barriers are
assessed for robustness and assurance is conducted to verify the performance of the
barriers and to identify any potential areas for improvement.
6.2
Lessons from Deepwater Horizon
On April 20, 2010, a well control event allowed hydrocarbons to escape from the Macondo
well in the Gulf of Mexico onto the Transocean DWH MODU, resulting in explosion and fire
on the MODU and the loss of 11 lives. BP Exploration and Production Inc. was the lease
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operator of the well. Hydrocarbons flowed from the reservoir through the wellbore and the
BOP for 87 days, causing a spill of national significance. In January 2015, the United States
District Court for the Eastern District of Louisiana found that 3.19 million barrels of oil
(MMbbl) were discharged into the Gulf of Mexico.
A BP priority is to prevent any similar oil spill from taking place. BP’s 2010 internal
investigation into the DWH incident, known as the Bly Report, concluded that no single
cause was responsible for the incident. A complex, inter-linked series of mechanical failures,
human judgments, engineering design, operational implementation and team interfaces
(involving several companies including BP), contributed to the incident.
BP’s internal investigation, which culminated in the Bly Report, involved a team of over 50
internal and external specialists from a variety of fields, including safety, operations, subsea,
drilling, well control, cementing, well flow dynamic modelling, BOP systems, and process
hazard analysis. Eight key findings relating to the causal chain of events were made, with 26
associated recommendations to enable the prevention of a similar accident and aimed at
further reducing risk across BP’s global drilling activities.
The eight key findings related to the cause of the DWH incident , as well as how these
lessons have been applied to this project in order to prevent a reoccurrence of the DWH
incident, are summarised below.
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Table 5 - Key Findings from the Deepwater Horizon Incident Relevant to this Project
Finding
Summary Description
Investigation Conclusion
Application to this Project
There were weaknesses in the
cement design and testing,
quality assurance and risk
assessment.
BP’s Zonal Isolation Practice was updated and clarified, establishing clear
requirements for annuar cement well barrier elements and verification of
these barriers during well construction, temporary abandonment and
permanent abandonment. BPs zonal isolation objectives, within the
Practice, are designed to prevent unintended movement of fluids between
distinct permeable zones (DPZ), flow to surface or seabed, development of
sustained casing pressure (SCP) during well operations due to
communications between a DPZ and the surface or seabed, and
contamination of potable-water aquifers.
Critical factor: Well integrity was not established, or failed
1. The annulus
cement barrier did
not isolate the
hydrocarbons.
The day before the accident, cement had
been pumped down the production casing
and up into the wellbore annulus to
prevent hydrocarbons from entering the
wellbore from the reservoir. The annulus
cement that was placed across the main
hydrocarbon zone was light, nitrified foam
cement slurry. This annulus cement did not
isolate the wellbore annulus from the
hydrocarbon zone.
BP’s established a comprehensive set of cementing documents to provide
clear engineering guidance to BP Engineers when designing cement jobs
to achieve zonal isolation requirements.
BP established a global Cementing Engineering Team to enhance
cementing discipline capability, to provide increased assurance of cement
designs and to fulfil the cement job design review requirements outlined in
the Zonal Isolation Practice.
BP conducted a review of the quality of the services provided by all
cementing service providers working with BP globally and new providers
are reviewed before their services are contracted.
BP provided leadership for a Work Group within the American Petroleum
Institute (API) that updated the industry recommended practice for the
preparation and testing of foamed cement slurries.
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2. The shoe track
barriers did not
isolate the
hydrocarbons.
Having entered the wellbore annulus,
hydrocarbons passed down the wellbore
and entered the 9 ⅞” x 7” production
casing through the shoe track, installed in
the bottom of the casing. Flow entered
into the casing rather than the casing
annulus. For this to happen, both barriers
in the shoe track must have failed to
prevent hydrocarbon entry into the
production casing. The first barrier was the
cement in the shoe track, and the second
was the float collar, a device at the top of
the shoe track designed to prevent fluid
ingress into the casing.
Hydrocarbon ingress was
through the shoe track, rather
than through a failure in the
production casing itself or up
the wellbore annulus and
through the casing hanger seal
assembly. Potential failure
modes were identified that
could explain how the shore
track cement and the float
collar allowed hydrocarbon
ingress into the production
casing.
BP’s updated Well Barrier Practice provides the requirements for the
design, selection, installation, maintenance, monitoring and management
of well barriers and well barrier elements throughout the full life cycle of
the well.
Per the practice, well barriers are generally required to isolate energy
sources within the earth from each other, the surface environment, and
people. Dual well barriers (primary and a secondary) are required between
energy sources and the surface. This BP practice applies to all wells
regardless of where they are in their life cycle, including those wells under
construction, actively in service, temporarily abandoned or permanently
abandoned.
Well barrier elements are verified to acceptance criteria in BP’s Well Barrier
Practice. For a cemented shoe track to be used as a well barrier element, it
must have two independent floats for redundancy to prevent backflow of
cement; have cement verified with a length and compressive strength
required in BP’s zonal isolation practice; and have successfully passed both
a positive test and a negative test as outlined in BP’s pressure testing
practice.
Critical factor: Hydrocarbons entered the well undetected and well control was lost
3. The negativepressure test was
accepted although
well integrity had
not been
established.
Prior to temporarily abandoning the well, a
negative pressure test was conducted to
verify the integrity of the mechanical
barriers (the shoe track, production casing
and casing hanger seal assembly). The test
involved replacing heavy drilling mud with
lighter seawater to place the well in a
controlled underbalanced condition. In
retrospect, pressure readings and volume
bled at the time of the negative pressure
test were indications of flow-path
communication with the reservoir,
signifying that the integrity of these
barriers had not been achieved.
The Transocean MODU crew
and BP well site leaders
reached the incorrect view
that the test was successful
and that well integrity had
been established.
BP’s practices address both the positive and negative pressure testing
requirements for wells. This updated practice requires prior approval of the
engineering procedures for negative testing, and also specifies the
minimum criteria to be met for a successful test.
The Well Site Leader interprets the results of the test against the
engineered acceptance criteria. The Well Superintendent, who has an offsite supervisory role, then approves the negative pressure test. Both staff
positions are classified as critical roles that undergo mandatory
competency assessments.
With the aim of building and maintaining competency of its staff, BP
delivers in-house industry-accredited well control training with staff
instructors and full-size drilling simulators in its own facilities in Houston,
Sunbury, and, from 2016, in Baku.
In addition, building on its Applied Deep Water Well Control course that BP
developed and delivered in recent years to its entire deep water rig fleet,
BP has an agreement with Maersk Training to use its state-of-the-art
immersive simulation training facilities and instructors to provide an
enhanced development program for rig teams. The integrated rig teams -including individuals from BP, drilling contractors and service companies -work through simulator-based scenarios to practice procedures, roles and
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responsibilities in challenging drilling and completion situations before they
potentially encounter those situations in actual operations.
4. Influx was not
recognized until
hydrocarbons were
in the riser.
5. Well control
response actions
failed to regain
control of the well.
BP’s well monitoring practice lists the responsibilities and requirements for
verifying and documenting that well monitoring has been properly
implemented. The requirements include alarm setting and actions to be
taken, fluid volume and density monitoring, flow checking, and actions to
verify conformance with the practice.
With the negative pressure test having
been accepted, the well was returned to
an overbalanced condition, preventing
further influx into the wellbore. Later, as
part of normal operations to temporarily
abandon the well, heavy drilling mud was
again replaced with seawater, underbalancing the well. Over time, this allowed
hydrocarbons to flow up through the
production casing and passed the BOP.
Indications of influx with an increase in drill
pipe pressure are discernible in real-time
data from approximately 40 minutes before
the rig crew took action to control the well.
The rig crew’s first apparent well control
actions occurred after hydrocarbons were
rapidly flowing to the surface.
The rig crew did not recognize
the influx and did not act to
control the well until
hydrocarbons had passed
through the BOP and into the
riser.
The first well control actions were to close
the BOP and diverter, routing the fluids
exiting the riser to the DWH mud gas
separator (MGS) rather than to the
overboard diverter line.
If fluids had been diverted
overboard, rather than to the
MGS, there may have been
more time to respond, and the
consequences of the accident
may have been reduced.
BP’s practices provide requirements and options for well control risk
mitigation, response, and remediation on all BP operated activity
throughout the lifecycle of a well. These practices incorporate enhanced
industry standards that BP and others developed to advance capabilities
across the industry following industry incidents.
BP’s practices outline the methods and tools to achieve design safety
through management of hazards. Managing hazards involves eliminating or
minimizing major accident hazards (MAHs) at source and preventing those
that remain from becoming major accidents. This may include equipment
and design modification before the MODU begins a drilling program. For
example, BP design requirements for mud gas separators have been
changed in order to divert gas overboard and not near equipment or
personnel.
The BP practice requires a tailored regional wellbore monitoring procedure
that is communicated to personnel with responsibilities for well
monitoring, including the rig contractor and mud logger.
The Well Site Leader, through BP’s self-verification and oversight process,
helps assure that the crew’s actions conform to the wellbore monitoring
procedure.
As described in item 3, BP well site leaders and superintendents undergo
competency assessments for their role. Relevant BP, rig contractor and
well services company staff are required to receive industry-recognized
well control certification. Also, BP provides enhanced, scenario-based
training for rig crews.
As described in item 3, BP well site leaders and superintendents are
required to undergo competency assessments for their role. BP, rig
contractor and well services company staff are required to receive
industry-recognized well control certification. Also, BP provides enhanced,
scenario-based training for rig crews.
Critical factor: Hydrocarbons ignited on Deepwater Horizon
6. Diversion to the
mud gas separator
results in gas
venting onto the
rig.
Once diverted to the MGS, hydrocarbons
were vented directly onto the rig through
the 12’ goosenecked vent exiting the
MGS, and other flowlines also directed gas
onto the rig. This increased the potential
for the gas to reach an ignition source.
The design of the MGS
system allowed diversion of
the riser contents to the MGS
vessel although the well was
in a high flow condition. This
overwhelmed the MGS
system.
7. The fire and gas
system did not
Hydrocarbons migrated beyond areas on
DWH that were electrically classified to
The heating, venting and air
conditioning system probably
In addition, BP conducts hazard and operability reviews (HAZOPs) of
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prevent
hydrocarbon
ignition.
areas where the potential for ignition was
higher.
Critical factor: The blowout preventer did not seal the well
Three methods for operating the BOP in
8. The BOP
the emergency mode were unsuccessful
emergency mode
in sealing the well.
did not seal the
well.
The explosions and fire very likely disabled
the emergency disconnect sequence, the
primary emergency method available to
the rig personnel, which was designed to
seal the wellbore and disconnect the
marine riser from the well.
The condition of critical components in the
yellow and blue control pods on the BOP
very likely prevented activation of another
emergency method of well control, the
automatic mode function, which was
designed to seal the well without rig
personnel intervention upon loss of
hydraulic pressure, electric power and
communications from the rig to the BOP
control pods. An examination of the BOP
control pods following the accident
revealed that there was a fault in a critical
solenoid valve in the yellow control pod
and that the blue control pod AMF
batteries had insufficient charge; these
faults likely existed at the time of the
accident.
Remotely operated vehicle intervention to
initiate the autoshear function, another
emergency method of operating the BOP,
likely resulted in closing the BOP’s blind
shear ram (BSR) 33 hours after the
explosions, but the BSR failed to seal the
well.
transferred a gas-rich mixture
into the engine rooms, causing
at least one engine to
overspeed, creating a potential
source of ignition.
surface gas and fluid systems for all BP-owned and BP-contracted drilling
rigs, which include a review of hydrocarbon vent locations and design.
There were indications of
potential weaknesses in the
testing regime and
maintenance management
system for the BOP.
BP’s Well Control Practice specifies that:
For additional assurance, BP’s Rig Engineering team inspects new MODUs
before well operations begin and all MODUs on a periodic basis.
•
all dynamically positioned (DP) rigs be equipped with subsea BOPs
that have two blind shear rams and a casing shear ram;
•
before beginning drilling new wells, a remotely operating vehicle
(ROV) demonstrates the ability to access the subsea BOP control
panel to pressurize and activate the shear rams;
•
a third party will certify that;
o the BOP has been inspected and its design reviewed in
accordance with the original equipment manufacturer (OEM)
specifications,
o modifications to the BOP, if any, have not compromised its
design or function,
o testing and maintenance of BOPs are performed in accordance
with OEM guidelines and API Standard 53.
•
This practice also requires confirmation by a shear specialist that
the BOP has the ability to shear drill pipe under maximum
anticipated surface pressure (MASP) conditions.
•
Also, BP maintains dedicated subsea BOP reliability personnel with
a global remit, to support all offshore BP drilling activities and can
be called upon to assist with BOP related issues. BP’s subsea BOP
reliability personnel work with its drilling contractors and their
original equipment manufacturers (OEMs) to monitor BOP
performance and further enhance BOP system reliability through
oversight of maintenance and testing.
•
Also, BP and others in industry have advanced industry standards
for BOP equipment through the American Petroleum Institute (API).
In addition, efforts through API, the International Association of Oil
and Gas Producers (IOGP), the International Association of Drilling
Contractors (IADC) and other industry groups is focused on sharing
information on BOP performance.
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6.2.1
Incorporating Lessons Learned
Every official investigation report released to date, including those from the Presidential
Commission, the US Coast Guard, the Bureau of Ocean Energy Management (Regulation
and Enforcement), and the National Academy of Engineering/National Research Council,
reinforces the Bly Report’s core conclusion that this was a complex accident with multiple
causes involving multiple parties.
The Bly Report recommended a number of measures to strengthen BP’s operational
practices, and these are being addressed through the implementation of enhanced drilling
requirements. Key areas that have been captured in guidance documents and engineering
technical practices are described below.
6.2.1.1
Cementing or zonal isolation
BP issued revised mandatory zonal isolation requirements and nine associated engineering
guidance documents covering key cementing activities. BP established a global Cementing
Engineering team to increase cementing discipline capability and provide increased technical
and operational assurance for cementing operations.
6.2.1.2
Integrating process safety concepts into the management of wells
BP produced a technical practice specifying minimum requirements for well barrier
management to manage the movement of fluids and gas during the life cycle of the well.
6.2.1.3
Well casing design
BP updated its design manual for well casing and tubing to include new requirements for
pressure tests and revised technical practices. BOP stacks – BP issued a revised technical
practice on well control, defining and documenting requirements for subsea BOP
configurations. BP requires two sets of BSR and a casing shear ram for all subsea BOPs
used on deepwater DP MODUs. BP also requires that third-party verification be carried out
on the testing and maintenance of subsea BOPs in accordance with recommended industry
practice, and that ROVs capable of operating these BOPs be available in an emergency.
6.2.1.4
Rig audit and verification
BP continued the MODU audit process that was enhanced in 2011. BP has conducted
detailed hazard and operability reviews for key fluid handling systems on all offshore
MODUs contracted to BP. New MODUs contracted to BP are subject to a full rig verification
assessment and ‘readiness to operate’ is verified with a detailed go/no-go process assured
by S&OR. This verification process includes a checklist, which among other things, assists in
assessing that the MODU conforms to applicable BP practices and industry standards and
has the right technical specification, and that all actions required for start-up are completed.
All MODUs are also subject to subsequent periodic rig verification assessments.
In addition to these technical requirements, BP has focused on enhancement of capability
and competency; verification, assurance and audit; and process safety performance
management.
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6.2.2
Progress on Recommendations of the Bly Report
Progress on implementing the recommendations from the Bly Report, BP’s investigation
into the DWH incident, from an independent expert appointed to provide an objective
assessment of this progress, concluded in February 2016 that all 26 Bly Report
recommendations had been closed out to his satisfaction. Further information is provided in
the BP 2015 Sustainability Report
(http://www.bp.com/en/global/corporate/sustainability/reporting.html).
The table below outlines progress against the Bly Report recommendations.
Table 6 : Progress Against the Bly Report Recommendations
Progress
No
.
Finding
1
Update and clarify cementing practice and guidelines.
Complete
2
Update requirements for subsea BOP configuration.
Complete
3
Update recommendations for negative pressure tests and lock-down rings.
Complete
4
Update practice on working with pressure, including contingency and testing
procedures.
Complete
5
Strengthen incident reporting standards for well control and well integrity.
Complete
6
Proposal of recommended practice for design and testing of foamed cement
slurries to API.
Complete
7
Assess risk management and Management of Change (MoC)processes for life
cycle global wells activities.
Complete
8
Strengthen the technical authority’s role in cementing and zonal isolation.
Complete
9
Enhance drilling and completions competency programs for key operations and
leadership positions.
Complete
10
Develop advanced deepwater well control training.
Complete
11
Establish BP in-house expertise for subsea BOP and BOP control systems.
Complete
12
Request the IADC to develop subsea engineering certification.
Complete
13
Strengthen BP’s rig audit process to improve closure and verification of audit
findings across the rigs BP owns and contracts.
Complete
14
Establish key performance indicators (KPIs) for well integrity, well control, and rig
safety-critical equipment.
Complete
15
Require drilling contractors to implement auditable integrity monitoring system.
Complete
16
Assess cementing service provider capabilities.
Complete
17
Confirm well control and monitoring practices are defined and applied.
Complete
18
Require hazard and operability reviews for surface gas and drilling fluid systems.
Complete
19
Include study of all drilling rig surface system hydrocarbon vents in all hazardous
operations (HAZOPS).
Complete
20
Establish minimum levels of redundancy and reliability for BOP systems.
Complete
21
Strengthen BP’s requirements for BOP testing by drilling contractors, including
emergency systems.
Complete
22
Strengthen BP’s requirements for BOP maintenance management systems by
drilling contractors.
Complete
23
Set minimum standards for drilling contractors’ MoC for subsea BOPs.
Complete
24
Develop a clear plan for ROV intervention for each subsea BOP.
Complete
25
Require contractors to verify BSR performance capability.
Complete
26
Include testing and verification of revised BOP standards in MODU audit.
Complete
(at end 2015)
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Through consultation with a multidisciplinary team drawn from Crisis and Continuity
Management, Environment, Wells and Reservoir Engineering, a range of potential spill
events have been identified based on oil type and operational activity, from which discrete
planning scenarios have been defined, that are then used to develop response strategies
and capability provisions. Planning scenarios provide the basic foundation of sound oil spill
planning and response capability. They collectively provide the full range of potential
impacts that may arise from the oil spills that could occur, and the full range of response
actions that would be needed to address this.
A list of the potential impacts and risks associated with potential unplanned event scenarios
are summarised in Table 7 .
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Table 7 - Environmental risk assessment summary – unplanned events
Hazard
Known and Potential Impacts
Risk
Key mitigation and management measures
Consequene
Likelihood
• Marine pollution resulting in
injury and entanglement of
marine fauna and seabirds
• The MODU and support vessels will have Garbage
Management Plans in place.
• MODU facilities are fit for purpose and free of defects
• All vessel and MODU crew undertake site inductions
which include a component on storing and handling of
hazardous materials and wastes.
Undetectable
Moderate
Not
or limited local
probability /
Significant
degradation
frequency
• Acute toxicity to marine
• Storage tanks, equipment, bunding and machinery
spaces are fit for purpose and free of defects.
• All vessel and MODU crew undertake site inductions
which include a component on storing and handling of
hazardous materials and wastes.
• All crew undertake spill response training every three
months in accordance with the SMPEP and training
matrix.
• Oil spill response kits are available in relevant locations
around the MODU, are fully stocked and are used in
the event of a spill.
Undetectable
Moderate
Not
or limited local
probability /
Significant
degradation
frequency
Significance
Accidental Release events
Accidental
release of solid
waste
Accidental
release of
materials during
operational and
maintenance
activities
Accidental
release of
materials during
bulk transfer
activities
fauna.
• Acute toxicity to marine
fauna.
• Storage tanks, equipment, bunding and machinery
spaces are fit for purpose and free of defects.
• Bulk hydrocarbons (including aviation fuel) are stored
within designated tank within a bunded area.
• The bunker transfer procedure is implemented in
order to prevent a mud spill. This includes: A PTW and
a JSA are undertaken for each transfer event, taking
into account spill response considerations.
• All drill fluids evaluated in accordance with GAB
Chemical Assessment Guideline.
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Undetectable
Low
Not
or limited local
probability
Significant
degradation
/ frequency
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Hazard
Known and Potential Impacts
Key mitigation and management measures
Risk
Consequene
Likelihood
Moderate
Low
Minor
degradation
probability /
Significance
Significance
• All vessel and MODU crew undertake site inductions
which include a component on bunkering and
chemical transfers.
• Communications between the MODU and the vessel
will be tested by the MODU Chief Mate and Vessel
Master prior to bunkering commencing.
• Transfer hoses are fitted with dry break couplings, are
inspected prior to each transfer and are replaced in
accordance with the PMS or when they are visibly
degraded.
• The integrity of storage systems and other equipment
will be assured through undertaking repairs as
necessary, and recording these in the PMS.
• Lifting procedures are implemented.
• A pre-spud ERP desktop exercise is undertaken to test
the emergency response mechanisms in place.
• The crew undertake spill response training every three
months in accordance with the SMPEP and training
matrix.
• Oil spill response kits are available in relevant locations
around the MODU, are fully stocked and are used in
the event of a mud, chemical or diesel spill to deck.
Accidental
release of drill
fluids during an
unplanned riser
disconnect.
Accidental
release from a
vessel collision
• Smothering and alteration of
benthic substrate; and
• Acute toxicity to marine
fauna from a reduction in
water quality.
• Acute toxicity to marine
fauna.
• Adherence to well specific operating guidelines.
• All drill fluids evaluated in accordance with GAB
Chemical Assessment Guideline.
• A pre-spud ERP desktop exercise is undertaken to test
the emergency response mechanisms in place.
•
Anti-collision monitoring equipment (e.g., 24-hour
radar watch, GMDSS and Automatic Identification
System [AIS]) on the MODU and support vessels is
functional and used in accordance with AMSA Marine
Orders Part 30 (Prevention of collisions).
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frequency
Moderate
Low
Minor
degradation
probability /
Significance
frequency
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Hazard
Known and Potential Impacts
Key mitigation and management measures
•
•
•
•
•
•
•
•
•
Accidental
release from a
well blowout
• Potential Toxicity effects /
Physical Oiling
• Potential for reduction in
•
Likelihood
Widespread
Low
damage
probability /
Risk
Significance
The MODU Watch Keepers are appropriately qualified
in accordance with AMSA Marine Orders Part 3
(Seagoing qualifications) (e.g., International
Convention of Standards of Training, Certification and
Watch keeping for Seafarers, STCW95, GMDSS
Proficiency) to operate radio equipment in order to
minimise the chance of collisions.
The PSZ is gazetted through NOPSEMA effective
from the MODU’s arrival at each well location.
Constant communications between the MODU and
support vessels are maintained to ensure the vessels
are patrolling the PSZ at all times.
The Vessel Masters issue warnings (e.g., radio
warning, flares, lights/horns) to third-party vessels
approaching the PSZ in order to prevent a collision.
One of the support vessels will remain with the
MODU at all times and will intercept approaching
vessels that have not heeded radio advice about the
presence of the MODU.
A pre-spud ERP desktop exercise is undertaken to
test the emergency response mechanisms in place.
A satellite-tracking buoy will be deployed from the
MODU immediately after a Level 2 or 3 diesel spill
(that occurs within the PSZ) in order to track the fate
of the spill.
BP ensures that operational monitoring takes place in
accordance with the OSMP in the event of a spill.
BP will provide the operational monitoring reports to
relevant regulatory agencies in order to characterise
environmental impacts from a diesel spill.
Safety critical equipment identified within Section 6.3
of the WOMP from BP Practice 100222 will be
utilized.
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Significant
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Hazard
event
Known and Potential Impacts
intrinsic values / visual
aesthetics.
• Potential damage to
commercial businesses.
Key mitigation and management measures
•
•
•
•
•
•
•
•
•
•
•
•
The fluid and cementing programs documented
within the WOMP from BP Practice 100222 will be
implemented.
A well programme will be developed prior to spud
and implemented.
The PMS will ensure safety critical equipment,
specifically the BOP will be maintained in accordance
with the manufacturer specifications.
Prior to use, the BOP will be subjected to an
Integrated Acceptance Test (IAT) Part 2 and signed
off by BP.
Prior to use, the BOP will be subjected to
independent third party verification against API
Standard 53.
The BOP will be tested in accordance with the
frequencies described in the BOP testing procedure.
BP will use a self verification and oversight model,
described in Section 4.4.2 of the WOMP to verify well
barriers throughout the duration of the drilling
program.
Practical barrier checks and frequency of self
verification and oversight will be implemented in
accordance with the GWO Safety Plan.
BP’s Competence Management Programme (CMP)
will ensure all personnel in safety critical roles are
assessed and the employees behaviours, skills,
knowledge and understanding verified to assure
competence.
A WOMP will be in place and accepted by NOPSEMA
for each well prior to spud.
The OPEP will be implemented in the event of a well
blowout.
Response preparedness will be undertaken in
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Consequene
Likelihood
frequency
Risk
Significance
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Hazard
Known and Potential Impacts
Key mitigation and management measures
•
•
•
•
•
accordance with the control measures identified
within the OPEP.
In the event of a well blowout, the containment
response plan will be implemented.
In the event of a well blowout, the relief well plan will
be implemented.
The Operational and Scientific Monitoring Plan
(OSMP) will be implemented in the event of a well
blowout.
Spill response exercises will be undertaken as a part
of the drilling program execution in accordance with
the OPEP.
BP’s Crisis Management Response System will be
implemented in the event of a well blow out event in
accordance with the OPEP.
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Consequene
Likelihood
Risk
Significance
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
7
Environmental Impact and Risk Evaluation – Oil Spill Response
Activities
In the unlikely event that all of the preventative measures described in earlier sections have
failed and a spill event has occurred, BP will have plans in place to launch multiple
simultaneous activities to stop the flow of hydrocarbons. These will make up BP’s mitigative
barriers. Similar to the preventative barriers outlined above, the mitigative barriers will
include process/ equipment, procedures and people.
BP has identified and defined a range of oil spill planning scenarios, and has determined
response strategies for each of these scenarios. Further details regarding response planning
are provided in Section 8.
Environmental impacts and risk evaluation has been conducted for these oil spill response
activities, as summarised in Table 8.
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Table 8 - Environmental risk assessment summary – oil spill response activities
Hazard
Known and Potential Impacts
Key mitigation and management measures
Consequence
Likelihood
Extensive
Moderate
damage
probability /
Risk
Significance
Additional potential impacts and risks from oil spill response activities
• Damage to or loss of
intertidal and shoreline
habitat;
• Disturbance to cultural
heritage sites;
• Temporary exclusion of
residents and tourists from
amenity beaches; and
• Secondary contamination of
foreshore and backshore
areas such as dunes.
• Net Environmental Benefit Analysis (NEBA) completed
by controlling agencies/hazard management agencies
prior to shoreline operations commencing.
• Cultural/heritage advice sought and considered as part
of NEBA processes.
• Cultural/heritage advisor appointed to the Incident
Management Team.
• Ongoing stakeholder consultation.
• Shoreline Cleanup Assessment Technique (SCAT)
Teams will assess shorelines for oiling and sensitivity
prior to operations commencing and control agencies
engaged and confirm shoreline treatment tactics.
Physical
interaction with
fauna
• Fauna casualties
• Trained personnel responsible for oiled wildlife
response.
• Maintenance of access to oiled wildlife personnel
through the National and Global oiled wildlife response
network.
• Wildlife response operations will be undertaken with
approval of the relevant state oiled wildlife response
agency.
Seabed
disturbance
• Smothering and alteration
of benthic habitat.
Ground
disturbance
Planned
discharge of
• Potential toxicity to pelagic
fauna and flora.
• No anchoring within TECs.
• NEBA completed prior to response operations
commencing.
• Dispersant Exclusion Zones.
• NEBA completed prior spraying dispersant oil.
• Only OSCA listed and approved dispersant will be used
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Significant
frequency
Moderate
Low
Minor
degradation
probability /
Significance
frequency
Moderate
Low
Minor
degradation
probability /
Significance
frequency
Widespread
Low
damage
probability /
Significant
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
Hazard
Known and Potential Impacts
dispersant
Key mitigation and management measures
for both surface and sub-surface application.
• The OSMP will be implemented.
• Daily NEBA conducted prior to surface dispersant
application.
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Consequence
Likelihood
frequency
Risk
Significance
GAB Exploration Drilling (Stromlo-1 & Whinham-1) EP Overview
8
Summary of Response Arrangements in the Oil Pollution Emergency
Plan
The project will operate under an Emergency Response Plan (ERP) and NOPSEMA accepted
OPEP to ensure timely response and effective management of any emergency. Bridging
documents will be prepared to link BP’s and Diamond’s safety management and well control
systems. To ensure readiness, emergency exercises and drills will be conducted prior to
commencement of drilling and regularly on-board the MODU. Any opportunities for improvement
identified as a result of conducting the exercise will be used to update emergency response
procedures, where necessary, to ensure a well-organised response to any emergencies during the
project.
The GAB drilling program OPEP details the BP incident management structures and arrangements
for dealing with an oil spill event from this project. It defines the arrangements from immediate
response to escalation for a worst credible case discharge event. This includes the full scalability
of the resources required.
8.1
Support Arrangements
The BP response capability has been designed around BP owned resources, those that are
accessible from within Australia, and those from the regional and global response networks.
These arrangements include the following:
•
A comprehensive equipment stockpile owned by BP and held at a number of locations,
including the Adelaide supply base;
•
BP capping and containment response equipment and personnel based in the US;
•
An agreement through full membership of AMOSC that provides access on a 24/7 basis to oil
spill response equipment, dispersant and specialist personnel in Geelong and Fremantle;
access to oil industry resources (Mutual Aid Stockpiles) and trained industry response core
group personnel; Fixed Wing Aerial Dispersant Capability (FWDC); and the Global Response
Network which provides mutual assistance during an oil spill event;
•
AMOSC master service agreement with the Australian Maritime Safety Authority (AMSA)
giving access to NatPlan response resources and the National Response Team (NRT);
•
An agreement through full membership with Oil Spill Response Limited (OSRL) that provides
an extensive range of oil pollution response equipment and specialist personnel from the
OSRL bases of operation in Singapore, Southampton, Bahrain and Fort Lauderdale;
•
Access to the Global Dispersant Stockpile via BP’s membership of AMOSC and OSRL, making
available very large volumes of approved dispersant; and
•
Support from the BP Mutual Response Team, which is a team of approximately 450 trained
personnel from BP global operations.
The GAB OPEP provides a first strike plan that details the tasks to mobilise an initial response and
the essential notifications that are required to be conducted.
It provides guidance for the IMT on all aspects of oil spill response and moves the response from
the initial reactive phase into the development of a full IAP planning cycle. It also defines the
necessary integration and liaison required with the relevant state agencies.
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8.2
Response Strategy Overview
BP has assessed available response tactics for application to the GAB, and has established oil spill
preparedness and response positions to demonstrate that impacts and risks associated with the
loss of hydrocarbons would be managed to ALARP and acceptable levels.
The response measures assessed and planned for are as follows;
•
Surveillance and tracking
•
Surface dispersant application (vessel and aerial)
•
Subsea dispersant injection
•
Subsea well capping stack
•
Relief well
•
Offshore mechanical containment and recovery
•
In-situ burning
•
Shoreline protection
•
Shoreline clean-up
•
Oiled wildlife response
•
Waste removal and management
A summary of oil spill planning for the GAB exploration wells is provided below. Further details
are outlined in the document ‘Oil Spill Response Planning Strategic Overview’ which is available
on the GAB website www.bpgabproject.com.au.
8.2.1
At-Sea Response Strategy
In the event of a loss of well control event, stopping the release of hydrocarbons to the
environment is achieved using a combination of the following tactics:
•
Closure of the BOP;
•
ROV mobilisation and external intervention;
•
Capping stack deployment; and
•
Drilling a relief well.
If the primary well control measures fail, BPs first course of action would be to attempt to close
the BOP. In the unlikely event that the BOP closure mechanisms fail, the next line of response
would be BOP intervention to establish control and ultimately shut in the well using an ROV.
Capping stacks provide a means of choking back flow, establishing a barrier and the subsequent
ability to pump heavier kill fluid into the well to control the pressure. A relief well is a longer-term
response option to stop uncontrolled flow from a well (i.e., ‘kill’ a well). A relief well is drilled to
intersect the well that is out of control to provide a conduit to pump high density fluid into the
well, and thus stop well flow.
Whilst source control activities are being undertaken, a combination of other oil spill response
tactics are implemented to mitigate the effects of the release of hydrocarbons to the environment.
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Given the potential impacts to both at-sea and nearshore receptors, the fundamental intent of the
oil spill response strategy will be to implement first, and closest to the spill source, those actions
that could deliver the most benefit (for both at-sea and nearshore receptors).
BP believes that the application of subsea dispersant injection (SSDI) offers substantial advantage,
based on the experience gained during the response to the DWH incident in the Gulf of Mexico in
2010. This showed that SSDI can be an effective response tactic for subsea oil blowouts, and can
offer a number of benefits. Application of SSDI will:
•
reduce the exposure of surface responders to the health and safety hazards of VOCs and oil;
•
enhance the dispersion of oil in the water column and so increasing the opportunity for natural
biodegradation;
•
treat oil released at the point of release;
•
require less dispersant compared to surface oil treatment;
•
can be conducted continuously, day and night and in practically any weather conditions, unlike
response tactics on the sea surface; and
•
ultimately help reduce the volume of oil that may come ashore.
Once SSDI is implemented, operations will run continually 24/7 while capping operations are being
prepared and carried out. Based on the experience of BP and the global industry, SSDI is
expected to take a period of around 10 days before it can be implemented.
As part of the overall response strategy, other response actions will be undertaken in this 10 day
period. Working backwards from Day 10, the on-water oil spill response strategy would comprise
a number of targeted measures, in coordination with the source control activities at the well site.
These strategies would include surface dispersant application and containment and recovery
activities.
8.2.2
Near-shore Response Strategy
Any oil that is not successfully dispersed, contained and removed close to the source will continue
to weather and move under the influence of currents and prevailing winds towards the coastline.
Depending on the season in which such an event might occur, the areas of coast that could be
affected will vary. The time for oil to reach the coast ranges from 9 days to several months and
the nature of the oil on the water will vary from patches/streamers of weathered and emulsified oil
and residues, through to traces of sheen.
If not managed, oil close to nearshore areas would be expected to strand on shorelines where it
may be expected to have a greater impact on amenities and some wildlife. Therefore, the main
focus for response will be removing as much oil from the sea surface as possible, which will
ultimately minimise shoreline loading as well as surface impacts to these areas.
Based upon a comprehensive planning evaluation, the response tactic expected to be appropriate
within near-shore areas include nearshore containment and recovery and protection and
deflection.
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8.2.3
Shoreline Response Strategy
At the outset of a well blowout event, much of the focus will be given to the rapid implementation
of source control and the at-sea response, with the aim of reducing the likelihood and extent of oil
reaching the shoreline as far as possible. However, the importance of preparing early for shoreline
protection and cleanup is also a high priority. BP have adopted an analogous approach to
concentric levels of shoreline response planning dependent upon probability and likely scale of
impact based on modelling outcomes.
From a planning perspective, appropriate shoreline protection and clean-up tactical response plans
(TRPs) have been developed. These tactical response plans include site specific details, response
tasks, site setup plans, concept of operations and a full resource inventory.
8.2.4
Oiled Wildlife Response Strategy
In the event that shoreline oiling cannot be prevented, BP will assess if there is a threat to wildlife
from the spilt hydrocarbon and, under the direction of the relevant Jurisdictional Wildlife Control
Agency, implement actions to reduce the consequences of the spill.
While WA and SA are working towards their own state and regional specific OWR plans, BP has
commissioned AMOSC to develop an Interim GAB Oiled Wildlife Response Plan (IGOWRP). This
plan has been developed in close consultation with these jurisdictions, with the intent that be it be
used by the relevant jurisdictional OWR Control Agencies until such time as it can be
subsumed/replaced by their own regional specific OWR plans.
9
Implementation Strategy
The Implementation Strategy described in this section is a summary of the BP systems, practices
and procedures that are in place to manage the potential environmental impacts described in the
EP and to ensure objectives associated with these potential impacts are met.
9.1
The BP Operating Management System
As one of the world’s leading integrated oil and gas companies, BP aims to create long-term value
for shareholders by helping to meet growing demand for energy in a safe and responsible way.
The BP Operating Management System (OMS) defines a systematic and consistent approach to
managing BP operating activities, helping to continuously improve performance while meeting a
commitment to operate safe, reliable and compliant operations.
BP’s OMS provides a single framework for BP operations, covering people, plant, process, and
performance. The OMS applies whenever BP carries out or uses a contractor to carry out
operating activities. It brings together BP requirements on health, safety, security, environment,
social responsibility and operational reliability, as well as related issues such as maintenance,
working with contractors and organisational learning, into a common management system.
The BP OMS has two purposes:
•
Managing health, safety, security and environmental (HSSE) and operational risks in our
operating activities by setting out what we need to do.
•
Improving the quality of our operating activities through an annual Performance Improvement
Cycle.
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9.2
Contractor Management System
BP has clearly defined practices which outline the processes and tools used in to procure and
manage goods and services. These practices are intended to drive effective management of
contractors in support of reduction of risk, improved operational performance, increased capital
productivity, reduced cost, and improved access to resources and markets.
Through specific contract requirements, BP requires that contracted companies have in place a
HSE management system that provides a systematic approach for controlling risk, complying with
regulatory requirements and continually improving HSE performance.
The key contractor for this drilling program, Diamond, manages HSE performance by their Global
Excellence Management System (GEMS), which is the equivalent of BP’s OMS. GEMS is a fullyintegrated Health, Safety, Environmental and Quality (HSEQ) system that contains the procedures
to monitor, control and continuously improve performance in these areas. GEMS is certified by the
IMO and by the International Management Code for the Safe Operations of Ships and Pollution
Prevention (ISM Code). Diamond’s Safety and Environmental Management System (SEMS) is part
of the overall GEMS, and provides a system containing the company’s policies, procedures and
guidelines for conducting operations in a safe and efficient manner. These systems provide a
consistent, worldwide management system for use on all Diamond facilities.
For vessel-based activities, BP will ensure that an Environmental Management System is in place
for the selected contractors to ensure that their environmental impacts and risks are adequately
identified and managed. The support vessel contractors must have systems in place to monitor
and track compliance with the requirements of this EP. Pre-qualification criteria and pre-selection
audits of potential vessel contractors will ensure these systems are in place prior to contract
award.
9.3
Roles and Responsibilities
In accordance with BP’s OMS, the environmental roles and responsibilities of key project
personnel are summarised in the EP. Whilst compliance with HSE requirements is the
responsibility of all personnel involved in the drilling program, the BP Global Wells Organisation
(GWO) New Ventures Wells Manager is responsible for ensuring all required plans, audits and
reviews are undertaken in accordance with the EP.
9.4
Training and Competencies
BP’s OMS defines the training and competency expectations for BP staff and contractors. BP
employees are selected, trained, developed and evaluated to ensure that they attain and maintain
the level of competency required for the position they hold. BP selects its contractors based on a
detailed tendering process, whereby the qualifications and experience of tendering companies are
used to select companies to fulfill specific duties than cannot be met by internal resources.
Globally, Diamond has established the Worldwide Competency (WWC) Program, which is
Diamond’s system for establishing and verifying the knowledge, skills and abilities of each
employee to perform their assigned job function in a safe and environmentally sound manner. The
training and competency requirements are a set of documents that reside in the SEMS. The OIM
is responsible for the implementation of the WWC Program on the MODU, and Diamond’s training
department is responsible for the coordination and administration of the competency program as
well as the documentation and record keeping of personnel training. Audits of the WWC Program
are conducted through the internal annual GEMS and IADC accreditation audits.
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All BP and Diamond personnel involved with the project, including third-party contractors, will
attend a project-specific pre-spud induction. This will cover various aspects of the project,
including environmental and EP awareness and compliance aspects, including:
•
Environmental regulatory requirements;
•
Environmental sensitivities and key risks;
•
Key environmental management procedures, including:
−
Mud and cement management.
−
Waste management (segregation, containment and disposal).
−
Spill prevention, preparedness and response.
−
Housekeeping.
− Incident reporting and recording.
Whilst on the MODU, all personnel will be involved in a number of different HSE meetings,
including weekly HSE meetings, Toolbox meetings (job safety analysis) before initiation on tasks
and daily ‘pre-tour’ HSE meetings.
9.5
Incident Recording and Reporting
BP’s OMS requires that BP records and reports environmental incidents. There are also
obligations to report incidents to NOPSEMA and other government departments within a specified
time period.
All breaches of this EP are considered non-compliances. Non-compliances may be identified
during an audit, inspection, crew observation or as a consequence of an incident.
All non-compliances must be communicated immediately to the appropriate offshore personnel
(i.e., the Wells Team Leader and/or OIM). This expectation will be reinforced at the induction and
at weekly HSE meetings. All incidents of EP non-compliance will be investigated as per Element 4
(Procedures) of the OMS. Following an investigation, remedial actions are developed to prevent
recurrence and tracked to completion. The outcomes of the investigations will be communicated
to the crew during the weekly HSE meetings.
The BP Environment Manager or delegate will ensure internal notification, investigation and
reporting of any environmental incidents is conducted in accordance with BP’s internal reporting
procedure, and that external reporting is conducted as required under relevant legislation or as
agreed to during stakeholder consultation.
9.6
Environmental Monitoring and Record Keeping
The risk assessment conducted in the EP includes requirements regarding environmental
monitoring. This monitoring will be conducted at the frequency outlined in the EP, and will
contribute to the EP end-of-well performance report, which will be submitted to NOPSEMA within
three months of completion of each well.
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9.7
Auditing and Review
9.7.1
Audit and Verification
BP’s Global Wells Organisation (GWO uses a system of checks and balances to verify the quality
of operations through a process consistent with OMS and BP Group system of internal controls.
Audits are conducted to:
•
Ensure that environmental performance outcomes and standards are being met through the
duration of the project;
•
Identify potential non-compliances and opportunities for improvement; and
•
Ensure that all environmental monitoring requirements are being conducted.
Diamond will conduct a number of audits as per the SEMS Audit Manual (part of Diamond’s
SEMS). Audit programs conducted by Diamond will include:
•
Internal rig audit program;
•
External rig audits;
•
Rig GEMS audits;
•
Shore base GEMS audits;
•
Rig personnel HSE audits;
•
Action items from alerts; and
•
Preventative actions from risk assessments.
9.7.2
Rig verification
BP will conduct an independent environmental and containment rig assessment prior to the rig
mobilising to the drilling location. This assessment will primarily focus on rig drainage, waste
water system, oil treatment system and secondary containment.
BP will also conduct an Integrated Acceptance Test (IAT) of the rig. Part one of the IAT will test
the functionality and operability of the main rig systems required during the well program, and will
focus on people, plant, and process for each task Diamond is assigned to carry out. Part two of
the IAT will focus on BOP testing. BP assessors will witness Diamond personnel surface testing
the BOP stack, latching up the BOP to the wellhead, and conducting a subsea pressure test. The
focus will be on the people, plant, and process for testing the BOP.
The BOP system is also independently verified by Lloyds prior to drilling
9.7.3
Support vessel audits
Prior to contract award, an inspection of the preferred vessel operator’s Common Marine
Inspection Document (as developed by the International Marine Contractors Association), or
Offshore Vessel Inspection Database (as developed by the Oil Company International Marine
Forum), will be conducted. These documents provide a standardised format for inspection and
reporting by a competent inspector. In addition to a review of these documents, BP will conduct a
pre-qualification audit of the contractor and acceptance of the nominated vessels to ensure that
they meet BP’s HSSE requirements.
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BP will provide vessel contractors with a summary list of applicable controls/performance
standards prior to the commencement of operations, and will work with the vessel contractors to
ensure appropriate measurement criteria are in place in order to ensure performance against
standards can be measured. Audit against these requirements will then be conducted as part of
regular EP compliance audits.
9.7.4
EP Compliance Audits
The following arrangements will be established to review performance of the project against this
EP:
•
A pre-mobilisation EP compliance audit of the MODU and support vessels will be conducted to
ensure that procedures and equipment are in place to enable compliance with the EP.
•
An EP compliance audit of the MODU at least once per well will be conducted by an
experienced and qualified HSE professional (with the first audit taking place within three
weeks of spud).
•
An EP compliance audit of each support vessel will take place at least once during the drilling
program.
•
Regular review and audit of specific aspects of EP compliance will be conducted by the
onboard SDR in conjunction with the BP Environment Manager.
Audit findings will be recorded and communicated to key personnel through an audit exit meeting
and formal audit report, and corrective actions will be recorded and tracked to closure through BPs
action tracking tool. A summary of the environmental audit results will inform the EP performance
reports submitted to NOPSEMA.
9.7.5
OPEP and OSMP readiness review
A major OPEP desktop exercise will be undertaken prior to spud to ensure readiness for
operations. Lower level desktop exercises will be scheduled throughout the drilling program to
ensure that plans remain current and that skills are maintained. An OSMP desktop readiness
assessment will also be undertaken prior to spudding the first well.
9.7.6
EP and OPEP Review
Under the OPGGS (E) Regulation 17(5), there is a requirement for a titleholder to submit a
proposed revision of the EP (including OPEP) before the commencement of any significant
modification or new stage of the activity that is not provided for in the EP currently in force.
Changes to the activity are to be managed via BP and Diamonds “Management of Change”
procedures. These processes aim to identify potential hazards and impacts when a permanent,
temporary, or emergency change in ‘people’, ‘plant’, or ‘process’ is undertaken or a ‘deviation’
occurs.
Potential impacts arising from the change or deviation shall be risk assessed and reviewed prior to
the change or deviation be ‘approved’ in the final step of the MoC process. Based on this
assessment, should the proposed change trigger a requirement to revise the EP and/or OPEP
under the Regulations, the updated EP and/or OPEP will be submitted to NOPSEMA for
acceptance.
While the EP is in force, it is also possible that new information may become available through a
number of sources, including (but not limited to):
•
GAB Research Program;
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•
Monitoring studies conducted as part of the drilling program;
•
Stakeholder input;
•
Government documents, such as CMR management plans; and
•
Audits, inspections and investigations.
The BP Environment Manager will make certain any relevant new information is identified by
coordination and review of monitoring studies as well as via participation in the GAB Research
Program Management Committee, the APPEA HSE Committee, integrated project meetings and
stakeholder consultation meetings.
AS for changes to the activity, the BP Environment Manager will revise the EP, OPEP and/or
OSMP accordingly. The updated documents will be submitted to NOPSEMA for acceptance if
they require resubmission.
10
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