GP 10-20 26 August 2008

Document No.
GP 10-20
Applicability Group
Date 26 August 2008
GP 10-20
Marine Geohazards Evaluation and

Assessment
Group Practice
BP GROUP
ENGINEERING TECHNICAL PRACTICES
26 August 2008 GP 10-20
Marine Geohazards Evaluation and Assessment
Introduction
The introduction to this ETP mirrors section 17 of the revised DWOP.
All Geohazard Evaluation activity shall conform to Engineering Technical Practice GP10-20 – Marine
Geohazards Evaluation and Assessment.
1.1. General
1.1.1. Marine Geohazard reviews shall include requirements for seabed clearance, environmental or
archaeological review, and top-hole Geohazard review.
1.1.2. Upon, or prior to, access to a new offshore exploration area, SPU Exploration Management
shall be informed of the fundamental risks to offshore operations from Marine Geohazards
within the leased area.
1.1.3. Every standalone offshore well, well cluster, template, or drilling platform operated by BP shall
have had a Shallow Hazards Assessment (SHA) produced that shall address the expected
drilling risks to a depth of 200m below the preferred setting depth of the first pressure
containment string or to a penetration of 750m below seabed, whichever is deeper.
1.1.4. The final SHA for a BP well shall be prepared and assured internally by a qualified individual
making use of all the facilities at the disposal of a BP staff geoscientist and shall follow the
protocol of the Offshore Site Investigation Manual.
1.1.5. An SHA shall state the expected risk of a hazard, shallow gas, water flow etc., being present by
using the appropriate BP risk classification scheme for the particular hazard in question, see
table below for shallow gas:
Classification Description
High An anomaly showing all of the seismic characteristics
of a shallow gas anomaly, that ties to gas in an offset
well, or is located at a known regional shallow gas
horizon.
Moderate An anomaly showing most of the seismic
characteristics of a shallow gas anomaly but which
could be interpreted not to be gas and, as such,
reasonable doubt exists for the presence of gas.
Low An anomaly showing some of the seismic
characteristics of a shallow gas anomaly, but that is
interpreted not to be gas although some interpretive
doubt exists.
Negligible Either there is no anomaly present at the location or
the anomaly is clearly due to other, non-gaseous
causes.
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1.1.6. An offshore well shall not be sited over the top of a shallow gas anomaly reported to have a
potential for having shallow gas presence greater than negligible without a documented
operational risk review having been carried out.
1.1.7. A new offshore drilling location to be occupied by a bottom founded rig, barge, or platform
shall be located on a high-resolution seismic survey line specifically acquired to address the new
location. (Ref 1.3.1)
1.1.8. On recommencement of surface hole drilling an SHA shall be reviewed and re-issued for any
well cluster, template or drilling platform where there has been a hiatus in drilling operations of
greater than two years, or where the shallow casing plan, has been amended e.g. deepening of a
casing shoe.
1.1.9. For a well that is the first BP well drilled in a basin, that has required Exploration Forum
approval or where the fundamental Geohazard Level is high, and / or a critical geohazard issue
has been identified, a qualified Hazards/pore pressure specialist shall be present aboard the rig
to witness the drilling of the top-hole section.
1.1.10. A review shall be undertaken for an SHA for any well that has been shelved for a period of
greater than a year to ensure: surface location, trajectory, target, or drilling plan has not changed
and the SHA contents remain valid. Where changes are identified an MOC process should be
applied.
1.1.11. If any anomaly is classified with a potential shallow gas presence greater than negligible by
shallow hazards assessment, then the surface position of the well shall be relocated outside the
anomaly to a location with negligible potential for shallow gas presence.
In the event that an acceptable location with negligible potential of shallow gas presence cannot
be identified, then shallow gas shall be assumed present for purposes of well planning and risk
mitigation. In such an event, a documented operational risk assessment shall be carried out,
reviewed and approved. The document shall consider the following as a minimum:
• Potential presence of shallow gas
• Potential of shallow gas being abnormally pressured, if present
• Alternate location
• Possible use of pilot hole
• Rig type and capabilities
• Kill mud requirements
• Pump capacity
• Operational practices
• Riser or riserless configuration
1.1.12. Mutually agreed, rig-specific, shallow gas procedures shall be established between BP and the
drilling contractor prior to the start of a well and shall cover foreseeable contingencies should
shallow gas be encountered.
1.1.13. Shallow gas and diverter drills shall be held prior to spud of all wells and regularly until the first
pressure containment string is set.
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1.1.14. A shallow gas kick encountered prior to setting the first pressure containment string shall not be
shut in. In such event of shallow gas flow, kill operations will immediately commence by
pumping fluid into the well at the maximum sustainable pump rate.
1.2. Floating Drilling Operations
1.2.1. Wells shall be drilled riserless until the first pressure containment string has been set, unless:
• It is a government regulation to drill with a riser and diverter installed
• A recirculating mud system is required to drill the hole for surface casing
Prior to use of a riser to drill hole for surface casing, a documented risk assessment shall be
performed to address associated risks of riser use.
1.2.2. The rig shall be maintained in a state of readiness to move off location whilst drilling surface
hole. Where a riser is installed, procedures for well control and riser unlatch will be established
in advance.
1.2.3. All floating drilling operations carried out with returns to the installation shall be carried out
with a diverter system installed.
1.3. Bottom Founded, Barge and Platform Drilling Operations
1.3.1. A high-resolution seismic survey shall be performed for all locations. New locations shall
always be chosen to fall upon a high-resolution survey line specifically acquired to address the
location.
1.3.2. Wells shall be drilled with a diverter system installed for all hole sections after setting structural
conductor or drive pipe and before setting the first pressure containment string.
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Foreword
This is the first issue of Engineering Technical Practice (ETP) BP GP 10-20 dealing with Marine
Geohazards Evaluation and Assessment. This Group Practice (GP) replaces the relevant parts of the
Drilling and Well Operations Policy BPA-D-01.
Description of Risk
The presence of unrecognised, or misinterpreted, Geohazards at the seabed or in the shallow section of
the overburden poses a significant risk to well operations, development projects and production
operations.
Marine Geohazards characterisation is, therefore, considered a zero tolerance activity within BP.
Errors associated in Marine Geohazards characterization have, in the past, lead to harm to people,
damage to the environment, and the undermining of BP’s operational reputation. To preclude the
recurrence of such events, Marine Geohazards requires a definition of practices that establish the
minimum requirements for performing evaluation and assessment of risk.
The purpose of this document is to establish the minimum requirements in Marine Geohazards
Evaluation and Assessment that aligns to the needs of the three related common processes:
Exploration (Ecp), Drilling and Completions (BtBcp) and Major Projects (MPcp). These requirements
should be met by both employees and contractors acting on behalf of BP in the execution of Marine
Geohazards projects in support of BP operated wells and development projects.
Note: This Practice reflects the balanced judgment of the BP Group and is based on experience
and inputs from a variety of sources. However, it should be recognised that risk can never be
eliminated and, as we learn, the Group may have to adjust the acceptable risk envelope and the
Minimum Requirements of this Practice. This would result in an updated edition of this Practice
being issued by the relevant authority.
What is the Marine Geohazard Recommended Technical Practice?
The Marine Geohazards Practice is intended to ensure that there is a formal approach to managing the
risks associated with the identification, assessment and evaluation of Marine Geohazards that could
effect our exploration, drilling, development and production operations, that these risks are identified,
assessed and controlled in a methodical way so that they can be avoided or mitigated in an effective
manner in design of well or facilities such as to remove or reduce the risks identified to an acceptable
level.
The Technical Practice is supported by the D&C function as an ETP and the Geoscience function as a
GeoRP.
The primary aim of this Practice is to prevent safety incidents or environmental damage. However, the
processes may be extended to include other aspects of performance.
This BP Practice sets out to describe a systematic approach for evaluation and assessment of risks
associated with Marine Geohazards that is fitted to align with the three main BP common processes:
Ecp, BtBcp and MPcp.
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The process seeks to define outputs, quality assurance review points and the relative roles of
Geological/Geophysical Site Investigation Specialists and Geotechnical Site Investigation specialists
and to define the hand-off process aligned to the CP structure.
Who is it for?
This Practice is intended for the use of following groups:
• Those directly involved in every day delivery of Marine Geohazard assessments in support of
drilling or facility engineering design and construction.
• Those in allied or overlapping skills segments that require understanding of their own linkage
or point of input to the Marine Geohazards Process such as Pore Pressure Specialists,
Environmental scientists, etc.
• Those for whom such assessments are required in support of their business needs as defined
by either BP Common Process or Policy definition, or by external regulatory requirements.
• Wells or Project management who require understanding of process fundamentals and

requirements to be able to understand budget requirements and schedule impacts
Copyright © 2008 BP International Ltd. All rights reserved.

This document and any data or information generated from its use are classified, as a
minimum, BP Internal. Distribution is intended for BP authorized recipients only. The
information contained in this document is subject to the terms and conditions of the
agreement or contract under which this document was supplied to the recipient's
organization. None of the information contained in this document shall be disclosed
outside the recipient's own organization, unless the terms of such agreement or contract
expressly allow, or unless disclosure is required by law.
In the event of a conflict between this document and a relevant law or regulation, the
relevant law or regulation shall be followed. If the document creates a higher obligation, it
shall be followed as long as this also achieves full compliance with the law or regulation.
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Table of Contents
Page
Introduction ..................................................................................................................................... 2
1.1. General....................................................................................................................... 2
1.2. Floating Drilling Operations......................................................................................... 4
1.3. Bottom Founded, Barge and Platform Drilling Operations ........................................... 4
Foreword ........................................................................................................................................ 5
1. Scope .................................................................................................................................... 9
2. Normative references............................................................................................................. 9
3. Terms and definitions........................................................................................................... 10
4. Symbols and abbreviations .................................................................................................. 13
5. Practice Structure ................................................................................................................ 14
5.1. Requirements and Recommendations ...................................................................... 14
5.2. Language.................................................................................................................. 14
5.3. References and Responsibilities ............................................................................... 15
6. Accountability....................................................................................................................... 15
6.1. Minimum Requirements ............................................................................................ 15
6.2. Recommendations .................................................................................................... 15
7. Competence ........................................................................................................................ 16
8. Exploration Pre-Access, Access .......................................................................................... 17
9. Exploration Portfolio Build .................................................................................................... 18
10. Exploration Prospect Definition, BtB Appraise-Select........................................................... 19
11. BtB Define-Execute.............................................................................................................. 21
Floating Drilling Operations.................................................................................................. 22
Bottom Founded, Barge and Platform Drilling Operations .................................................... 22
12. MPcp Appraise .................................................................................................................... 22
13. Satellite Exploration and Drilling Renewal ............................................................................ 23
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Annex A Fundamental Marine Geohazard Risk Evaluation .......................................................... 25
A.1. The Geohazard Risk Pictogram ........................................................................................... 25
A.1.1 Shallow Structural Complexity................................................................................... 25
A.1.2 Regional Seismicity................................................................................................... 26
A.1.3 Shallow Deposition Rate ........................................................................................... 27
A.1.4 Shallow Hydrocarbon Presence ................................................................................ 27
A.1.5 Database Quality ...................................................................................................... 28
A.1.6 Pictogram Display ..................................................................................................... 29
A.1.7 Fundamental Geohazard Risk................................................................................... 29
A.2 The Geohazard Risk Cross Plot.............................................................................................. 29
Annex B Geohazard CRS Map Construction................................................................................ 31
B.1 General................................................................................................................................ 31
B.2 CRS Map Colours ................................................................................................................ 31
B.3 CRS Map Component Layers .............................................................................................. 31
B.3.1 Seabed Slope Angle ................................................................................................. 31
B.3.2 Slope Stability Stand-off Zones ................................................................................. 32
B.3.3 Seabed Environmental Constraints ........................................................................... 32
B.3.4 Archaeological Features or Munitions Disposal Zones .............................................. 33
B.3.5 Shallow Gas Anomalies ............................................................................................ 33
B.4 Superimposed Line Detail .................................................................................................... 34
B.4.1 Seafloor Geomorphological Elements ....................................................................... 34
B.4.2 Seafloor or Shallow Faults ........................................................................................ 34
B.4.3 Shallow Soils Provinces ............................................................................................ 34
B.5 Chart Commentary............................................................................................................... 34
B.6 Management of Change ...................................................................................................... 35
Annex C Integrated Geological Model.......................................................................................... 36
C.1 Start Point............................................................................................................................ 36
C.2 Final Desired Outcome ........................................................................................................ 36
C.3 Model Review ...................................................................................................................... 36
C.4 QRA..................................................................................................................................... 37
Annex D Marine Geohazard Peer Review Terms of Reference.................................................... 38
D.1. Review Team (minimum requirements):............................................................................... 38
D.2. Site Investigation Project Team Participants: ...................................................................... 38
D.3. Objectives:........................................................................................................................... 38
D.4. Desired Outcomes ............................................................................................................... 39
Annex E Administration................................................................................................................ 40
E.1. Administration and Authorisation.......................................................................................... 40
E.2 Auditing, Compliance and Deviation .................................................................................... 40
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1. Scope
This Practice applies to work on any BP operated offshore well or offshore development project
(Field, Transportation or Communications).
A BP Company is a company in the BP Group or other legal entity where BP has operational control,
is responsible for HSSE, and has the right to impose these requirements.
In situations where BP does not have control (i.e. a joint venture where BP is not the operator) BP
staff should endeavour to ensure that the operator implements processes that meet the minimum
requirements in this document.
The marine geohazard practice does not detail requirements for assessment and clearance of
geohazards for onshore wells or engineering projects.
For onshore wells a detailed review of historical data from offset wells shall be performed to assess
the potential of encountering geohazards such as shallow gas. This review should be an integral part of
the No Drilling Surprises process in the well planning.
For any onshore construction, or engineering, projects the geohazards review process should follow
the rationale set out in ETP GP 43-27 issued by the Geotechnical Engineering Segment Technical
Authority (GESeTA).
Applicability
For the purpose of this Group Practice, the workforce comprises BP employees and every employee of
any other company or other legal entity that has been engaged to perform work on BP-operated
reservoirs or production/injection infrastructure. A BP-operated reservoir for the purposes of this
document includes any site or location used for the injection or extraction of fluids that is owned or
operated by or for a BP Company.
In situations in which BP does not have control (i.e. a joint venture where BP is not the operator) BP
should attempt to persuade the operator to employ practices at least meeting the Minimum
Requirements in this document.
In the event of a conflict between this Group Practice and a relevant law or regulation, the relevant law
or regulation will be followed. If the Group Practice creates a higher obligation, it should be followed
as long as full compliance with the law or regulation is achieved.
Subject to the Group Practice’s intent and subject to existing contractual constraints (to the extent that
they cannot be renegotiated) this Group Practice shall be applied to all contractors and their associated
subcontractors who perform work on BP-operated reservoirs or on behalf of BP and shall be
incorporated in all tenders and contracts.
2. Normative references
The following normative documents contain requirements that, through reference in this text,
constitute requirements of this technical practice. For dated references, subsequent amendments to, or
revisions of, any of these publications do not apply. However, parties to agreements based on this
technical practice are encouraged to investigate the possibility of applying the most recent editions of
the normative documents indicated below. For undated references, the latest edition of the normative
document referred to applies.
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BP
BPA-D-001 BP Drilling & Well Operations Practice
BPA-D-005 Offshore Site Investigation Manual
BP Seafloor Hardground & Chemosynthetic Community Interpretation Guide Points
BP Shallow Gas Interpretation Guide Points
BP Shallow Water Flow Interpretation Guide Points
Drilling and Completions - Common Process Guidelines,
Issue 2, August 2004
Exploration & Production - Exploration Common Process,
2006
Exploration & Production - Major Projects Common Process,
Version 2, February 2007
Exploration & Production - Major Projects Common Process, Appraisal Guideline,
September 2007
GP 43-27 Managing Terrain Issues and Geohazards in Onshore Pipeline Projects
ISO Petroleum and Natural Gas Industries – Specific Requirements for Offshore Structures
Part 2: Seismic Design Procedures and Criteria
BS EN ISO 19901-2: 2004
3. Terms and definitions
For the purposes of this GP, the following terms and definitions apply:
Accountable Person
The person in the organization who has ultimate responsibility.
Appraise
Initial stage of a CVP process, for example in MPcp.
Assess
To consider and make a judgment upon.
Assurance
A guarantee, giving certainty.
Auditing
A formal or official examination and verification. The audit process should include monitoring,
review, and reporting of the outcome of the audit to those people who can implement any changes
needed.
Authority
Official permission.
A position that has the power to make a judgement; an individual cited or appealed to as an expert.
The power to influence or command.
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BP
BP, and no other former meaning as an abbreviation
BP Company
A company in the BP Group, or a company or other legal entity where BP has operational control, is
responsible for HSSE and has the right to impose this Standard.
BP Employee
A person employed by a BP Company.
BP Operations
BP Business Units, projects, facilities sites and operations
BP Premises
Any site, location or marine vessel that is owned or operated by or for a BP Company.
Competency
The ability to perform a task in the correct manner with the correct understanding and reasoning
behind the task.
Competent Person
A person who has demonstrated that they have the knowledge, training and experience required to
perform the defined role to the standard required.
Confirm
To support or establish the certainty or validity of; verify.
Contractors
A Company or individual who is under a contractual relationship to supply BP plc or one of its
subsidiary companies with Goods and Services and is working solely for the benefit of BP.
A contractual relationship includes:
• All individuals contracted directly or sub-contracted.
• All employees of companies contracted directly or sub-contracted.
• All situations where a contract has not been raised but BP’s procurement policy would
normally expect there to be a contract in place. This applies to all levels including sub-
contracted relationships.
Note: For the purposes of HSSE reporting any sub-contractor should be treated as if they held a
contract directly with BP plc or one of its subsidiary companies.
Control
a) A mechanism used to regulate a physical process or activity.
b) An action to mitigate risk.
c) The power to direct (usually through authority).
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Document Control Management System

An established means of controlling the issue, use and updating of documents used in the management
of a site. A full document control management system (DCMS) will include reference numbers on
documents, means of tracking changes and updates and regular audits of the system to confirm
compliance.
Eliminate
To remove or get rid of.
Formal
A formal process or agreement is one that is written, recorded and audited. It may also include
tracking to confirm that work is following the process or agreement.
Minimum Requirements
The activities, tasks or deliverables that shall be completed to comply with this Practice.
Monitoring
The routine function of regular inspection carried out by a responsible and competent person.
Operational Control
Where BP has responsibility for the activity as owner or under a contractual obligation with the
owners of the entity and, as a consequence, has appropriate authority to manage directly all HSSE
aspects of the operational activities to meet BP policy and expectations.
Plan
The function of task (work) identification, interaction and sequencing including, preparation and
completion requirements, to achieve an outcome.
Policy
Plan of action pursued by the Company (BP) with which all personnel shall comply.
Procedure
A detailed document either in paper or electronic form which sets out sequential or parallel actions
which shall be followed by those engaged in carrying out an activity.
Process
A detailed description of a management system or a production operation.
Risk
Possibility of loss, injury, damage, or exposure to hazard or danger.
Risk Assessment
The process of hazard identification and the assessment of the potential for identified hazards to be
realised in any given activity.
Roles
The documented description of personnel functions within a management structure.
Routine
A procedure that does not vary in its execution.
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Single Point Accountable

The person in the organization (site/Business Unit) who has been appointed as being accountable for
the delivery and performance of an activity.
Succinct
Clear, precise expression in few words.
Training
The bringing of a person to a desired degree of proficiency in some activity or skill. Training should
only be carried out by people who have been assessed as being competent to train.
Task
An activity in support of a piece of work.
Work
An activity made up of a number of different tasks.
Workflow
An activity made up of a sequence of different tasks designed to deliver a desired outcome.
Workforce
BP employees and every employee of any other company (includes all contractors) or other legal
entity that has been engaged to perform work on BP Premises.
4. Symbols and abbreviations
For the purpose of this GP, the following symbols and abbreviations apply:
BtBcp The D&C Beyond the Best Common Process
CoP Community of Practice, the Geoscience replacement for “Network.”
cp Common Process
CRS Common Risk Segment
CVP Common Value Process
D&C Drilling and Completions
DCMS Document Control Management System
DWOP Drilling and Well Operations Policy (BPA-D-001)
Ecp Exploration Common Practice
ETP Engineering Technical Practice, the D&C and Engineering equivalent of a GeoRP.
GDE Gross Depositional Environment
GeoRP Geoscience recommended practice. The Geoscience equivalent of an ETP.
GESeTA Geotechnical Engineering Segment Technical Authority
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GIS Geographical Information System
HoD Head of Discipline
HSSE Health, Safety, Security and Environment
MGTA Marine Geohazards Technical Authority
MPcp Major Projects Common Process
NDS No Drilling Surprises, a key strand of the BtB common process
PPFG Pore Pressure Fracture Gradient
OMS Operating Management System
OSIM Offshore Site Investigation Manual (BPA-D-005)
SeTA Segment Technical Authority
SHA Shallow Hazards Assessment, the more up to date name of what was formerly a Shallow
Gas Assessment
S&SI Survey and Site Investigation, a geoscience functional community of practice.
SOR Statement of Requirements, a key output of the BtB process.
SPA Single Point of Accountability
SPU Strategic Performance Unit
TAM Technical Appraisal Memorandum
TVP Technology Vice President
5. Practice Structure
5.1. Requirements and Recommendations

Minimum Requirements and Operational Excellence
Minimum requirements describe the minimum processes and activities that shall be completed
to deliver the intent of this Practice. These Minimum Requirements shall become the
“benchmark” for acceptable operating within BP.
Recommendations provide details of good practice – both internal and external to BP – which
go beyond the Minimum Requirements of this Practice. These are intended to provide options
for continuous improvement that will take businesses beyond the “getting the basics right” and
towards operational excellence. Adherence to recommendations will not be required to meet the
intent of this Practice.
5.2. Language
Shall, Should, will and May
Throughout the BP Group OMS Practices, when used in the context of actions by BP, or others,
and to be consistent with Engineering Technical Practices (ETP’s), the following words have
specific meanings:
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• 'Shall' is used where a provision is mandatory.

• 'Should' is used where a provision is preferred.
• 'Will' is used normally in connection with an action by BP, rather than by a contractor
or supplier.
• 'May' is used where alternatives are equally acceptable.
5.3. References and Responsibilities

References
References, where appropriate, are made to other relevant Policies, Common Process,
guidelines, procedures and documents that may be used in order to support the application of
this Practice or its fit to higher level BP Policies or Common Processes.
Schematics are provided to aid clarity and understanding. Annexes are provided to provide
detailed description of Output documents.
Note: It is important that all locally held documents relevant to the Practice process are
readily identifiable and accessible by the workforce.
Responsibilities
Where appropriate, roles and responsibilities to deliver any process/activities required within
this Practice are clearly defined. Delivery of these responsibilities will be locally assigned.
6. Accountability
Intent
BP Executives, Managers, and Supervisors shall actively participate in and recognize that effective
technical management of this zero tolerance activity is critical to our business success. Clearly
identifying the roles, responsibilities, and competencies for both BP employees and contractors and
holding them accountable for desired behaviors and performance is essential to effective marine
geohazards evaluation and assessment.
6.1. Minimum Requirements

a. A Single Point of Accountability (SPA) shall be defined for the delivery of each phase of
the technical practice for any offshore exploration area, well or development project (Field,
Transportation, or Communications project).
b. The SPA shall be responsible to ensure that the minimum requirements set out in this
Engineering Technical Practice are fulfilled.
c. The Marine Geohazards process adopted by an SPU shall meet all the local regulatory
requirements of the country in which the operation, or development, is to be delivered,
unless pre-agreed with the appropriate regulatory agency.
The Marine Geohazard reviews shall include requirements for seabed clearance,
environmental or archaeological review, and top-hole Geohazard review.
6.2. Recommendations
a. The Marine Geohazards Technical Authority should be consulted by the SPA for
clarification of Geohazard recommended practices as required or where uncertainty exists
on applicable standards.
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26 August 2008 GP 10-20
b. SPA’s for Marine Geohazards should participate in Survey and Site Investigation (S&SI)
Community of Practice (CoP) activities to maximize knowledge shared with other parts of
the organization.
• Be a member of the S&SI email distribution list
• Attend or participate in S&SI CoP meetings.
c. The Marine Geohazards Technical process should be delivered in a manner that supports
the stage requirements of the three key BP Common Processes: Exploration Common
Process (Ecp), Beyond the Best Common Process (BtBcp), and Major Projects Common
Process (MPcp). As described, below, the process is mapped to stages of these Common
Processes.
7. Competence
Intent
To ensure that individuals involved in delivery of Marine Geohazards analyses have the necessary
experience, capability, and knowledge to undertake the work in a manner that meets BP’s
expectations.

a. The final (SHA) for a BP well shall be prepared and assured internally by a qualified
individual making use of all the facilities at the disposal of a BP staff geoscientist and shall
follow the protocol of the Offshore Site Investigation Manual.
a. All outputs of this process should be independently peer reviewed by a BP Geohazards
Specialist and, or, Geotechnical Engineer who has not been directly involved in the
project.
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26 August 2008 GP 10-20
TDM TAM FIND!
Access Portfolio Build Prospect Definition Drilling
XR Op’g XPU World

Ecp
Screen Select Define Execute
Regional Fairw ay Prospect Field
Pre-Screen Hi-Grade OSIM
Outputs Aqn Aqn

GZtp

Risk F’nds GTL TAM inputs def’d SHA Dev’p Integ’d Geol Mod Quant Risk and Engr’g
BtBcp
Site Investigation Specialist Geotechnical Engr.
Appraise M Pcp
QA

Only by XF M GTA M GTA

At’st Request GESeTA/ SGE
M GTA
GESeTA/ SGE
Figure 1: M apping the Geohazards Technical Practice to key Common Processes
8. Exploration Pre-Access, Access
Intent
To ensure that fundamental Marine Geohazard risks are properly communicated to Exploration
management prior to, or upon access to, a new exploration area. That risk is placed in its proper
context against other exploration, or operational, areas within the BP portfolio. To ensure an
appropriate forward agenda is set at the outset to properly address risk, in terms of the immediately
required activity set, and potential budget and schedule implications.

a. Upon, or prior to, access to a new offshore exploration area, SPU Exploration Management
shall be informed of the fundamental risks to offshore operations from Marine Geohazards
within the leased area.
b. The SPU shall have an outline forward plan agreed with the MGTA as to how Marine
Geohazard risks shall be managed through to the end of BtB Select.
a. Prior to, or upon, access to a new offshore exploration area the MGTA, or their approved
delegate, should produce a memorandum that sets out the fundamental marine geohazard
risks, and their manageability.
b. The memorandum (Output 1) should be submitted to SPU Project Exploration
Management and copied to the HoD Exploration.
c. The memorandum should include the Standardized Geohazard Risk Pictogram for the area
under consideration and a cross-plot of Marine Geohazard Risk vs. Manageability. The
cross-plot should include a representative population of other BP operational areas, or
projects, to demonstrate relativity of risk faced in the new area. (Annex 1)
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26 August 2008 GP 10-20
d. The memorandum should, clearly and succinctly, describe perceived risk and set the
forward agenda for the effort (data requirements, analysis, timing, potential budgets, etc.)
required to review and refine understanding of risk up to end of BtB Select.
e. If produced by a delegate, before issue, the memorandum should be agreed with and
countersigned by the MGTA.
f. The Geohazard Risk and Manageability Memorandum should thereafter be updated at key
stages of the Exploration and Drilling common processes and up to the end of Major
Projects Appraise (Output points 2 – 4 inclusive).
TDM TAM
Access Portfolio Build Prospect Definition Ecp

Regional Fairw ay Prospect Field
Pre-Screen Hi-Grade OSIM
Outputs Aqn

Risk Fundamentals Set Risk Fundamentals Review ed Risk Fundamentals Refined

M GTA, or delegate, Geohazard CRS Stop Light CRS linked Aqu’n Strategy
review of XR
access opportunity
Develop Geohazard CRS or “ Stop
to assess
Geohazard risk
Light” map using standardized
approach akin to Exploration CRS
TAM Dev and Appraise Plan inputs
GZtp
fundamentals and
development. Construct and Risk linked acquisition and analysis
manageability.
capture in GIS form. strategy defined and follow ed through
Output in to issue of SHA, aligned w ith OSIM
Initial statements on Drillability,
standardized risk and fundamentals of BtBcp / NDS.
Developability and Appraise Plan
figure, such as
requirements drafted for TAM . Geohazards Appraise Plan and budget
pentagon, cross
set. TAM statements agreed for input.
plot and supporting Gate review by M GTA and
M emo to XR / XF. GESeTA/SGE. Standardized risks M GTA, or delegate, review of SHA. SHA
review ed / sense checked. Standardized risks refined for develop.
Site Investigation Specialist Geotechnical Engr.
QA

Only by XF M GTA
Attestation Request GESeTA/ SGE
M GTA
Figure 2: M arine Geohazards Practice in Support of Ecp
9. Exploration Portfolio Build
Intent
To produce Marine Geohazard Risk Common Segment maps in a standardised form, in parallel to the
exploration screening process producing GDE and CRS maps, at regional or fairway level, to allow
spatial analysis of Marine Geohazard risk to be available in the prospect ranking process, and to
initially engage senior geotechnical engineers in an initial review of development implications.
a. During the Screening stage, post Exploration Access, Marine Geohazard Common Risk
Segment maps should be produced using a standardised approach that define the spatial
variability of Marine Geohazards risk upon drilling and developability. Across the area of
interest (Annex 2),
b. The maps produced should be input and stored in the Project and/or Strategic Performance
Unit (SPU) Geographic Information System (GIS) and maintained and updated as the
opportunity moves from fairway, to prospect, to appraise stage (post discovery).
c. A short report should be written that reviews the maps and makes outline statements on:
Drillability, the data [gathering] strategy to support analyses for drilling planning,
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26 August 2008 GP 10-20
Developability issues, and an outline of Appraise requirements to support development

planning.
d. The work should be Peer Reviewed by the MGTA, or chosen delegate, the Geotechnical
Engineering Segment Technical Authority (GESETA) or their chosen delegate Senior
Geotechnical Engineer (SGE).
e. The peer Review should deliver: an update of the Geohazard Risk Memorandum for
submission to Exploration management to demonstrate progression of risk understanding,
and draft paragraphs for inclusion in a Technical Appraisal Memorandum on Drillability,
Developability and Appraisal Plan requirements for site investigation.
Sit Key Lessons

OSIM Process Wells Learnt
• Align/entw ine the Geohazards Technical Practice w ith the NDS Assessment Tool
• Ensure Geohazards Technical Practice output(s) remain aligned w ith BtB requirements for SOR at end of Select
• M aintain a sense checking presence through Define to ensure SHA message capture in risk mitigation in w ell design
• Witness the top-hole section of “ key” w ells ~ w here appropriate risk/value has been defined (new frontier areas)
• Ensure capture of lessons learnt by appending “ As Drilled” feedback and assessment as an addendum to SHA’s
Figure 3: Align w ith BtB: Embedding OSIM into NDS
10. Exploration Prospect Definition, BtB Appraise-Select
Intent
At this stage the process seeks to ensure that risks are properly communicated to Drilling Engineers,
and that an outline forward plan is in place to allow an efficient and effective start to MPcp Appraise
in the case of discovery of economic volumes.
Critically, the risk to offshore drilling from shallow Geohazards: gas, water flow etc., shall be
addressed in a timely manner to allow risk mitigation through move of drilling location or well design.

a. Every standalone offshore well, well cluster, template, or drilling platform operated by BP
shall have had a Shallow Hazards Assessment (SHA) produced that shall address the
expected drilling risks to a depth of 200m below the preferred setting depth of the first
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pressure containment string or to a penetration of 750m below seabed, whichever is

deeper.
b. An SHA shall state the expected risk of a hazard, shallow gas, water flow etc., being
present by using the appropriate BP risk classification scheme for the particular hazard in
question, see table below for shallow gas:
Classification Description
High An anomaly showing all of the seismic characteristics
of a shallow gas anomaly, that ties to gas in an offset
well, or is located at a known regional shallow gas
horizon.
Moderate An anomaly showing most of the seismic
characteristics of a shallow gas anomaly but which
could be interpreted not to be gas and, as such,
reasonable doubt exists for the presence of gas.
Low An anomaly showing some of the seismic
characteristics of a shallow gas anomaly, but that is
interpreted not to be gas although some interpretive
doubt exists.
Negligible Either there is no anomaly present at the location or
the anomaly is clearly due to other, non-gaseous
causes.
c. An offshore well shall not be sited over the top of a shallow gas anomaly reported to have
a potential for having shallow gas presence greater than negligible without a documented
operational risk review having been carried out.
d. A new offshore drilling location to be occupied by a bottom founded rig, barge, or
platform shall be located on a high-resolution seismic survey line specifically acquired to
address the new location. (Ref 11.1.j).
e. On recommencement of surface hole drilling an SHA shall be reviewed and re-issued for
any well cluster, template or drilling platform where there has been a hiatus in drilling
operations of greater than two years, or where the shallow casing plan, has been amended
e.g. deepening of a casing shoe.
a. Data acquisition should be based upon the risk assessment carried for the prospect or
fairway and upon the local regulatory requirements. Decisions on data types and data
density should reflect the specific risks faced on a project-by-project basis. The decision
process should be in keeping with the rationale set out in the Offshore Site Investigation
Manual (OSIM).
b. Marine geohazards analysis should be undertaken as an integral part of the No Drilling
Surprises (NDS) process for a wells project in BtB, rather than in parallel with, or
tangential to, it.
c. An SHA should be issued prior to the completion of the Select Stage of the BtBcp to allow
inclusion in the Statement of Requirements (SOR).
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d. The results of the marine geohazards analysis in the SHA should be integrated with the
other elements of the NDS process; pore pressure prediction etc. inconsistencies should be
clarified or eliminated.
e. Mapping outputs from the marine geohazards analysis should be shared in common earth
model for the well and, where appropriate, in the project GIS.
f. The Marine Geohazards Process should output brief paragraphs that are agreed with
exploration management for inclusion in the Technical Appraisal Memorandum (TAM)
pages on Developability, Drilling Risk and Appraise Plan for the prospect that is planned
for drilling.
11. BtB Define-Execute

a. For a well that is the first BP well drilled in a basin, that has required Exploration Forum
approval or where the fundamental Geohazard Level is high, and / or a critical geohazard
issue has been identified, a qualified Hazards/pore pressure specialist shall be present
aboard the rig to witness the drilling of the top-hole section.
b. For the first well, or pilot hole, at a development location (platform or template or well
cluster) where the fundamental Geohazard Level is high or a critical geohazard issue has
been identified, a trained Hazards specialist shall be present aboard the rig to witness the
drilling of the top-hole section and provide immediate update to Drillers on variations to
pre-spud prognosis.
c. If any anomaly is classified with a potential shallow gas presence greater than negligible
by shallow hazards assessment, then the surface position of the well shall be relocated
outside the anomaly to a location with negligible potential for shallow gas presence.
In the event that an acceptable location with negligible potential of shallow gas presence
cannot be identified, then shallow gas shall be assumed present for purposes of well
planning and risk mitigation. In such an event, a documented operational risk assessment
shall be carried out, reviewed and approved. The document shall consider the following as
a minimum:
• Potential presence of shallow gas
• Potential of shallow gas being abnormally pressured, if present
• Alternate location
• Possible use of pilot hole
• Rig type and capabilities
• Kill mud requirements
• Pump capacity
• Operational practices
• Riser or riserless configuration
d. Mutually agreed, rig-specific, shallow gas procedures shall be established between BP and
the drilling contractor prior to the start of a well and shall cover foreseeable contingencies
should shallow gas be encountered.
e. Shallow gas and diverter drills shall be held prior to spud of all wells and regularly until
the first pressure containment string is set.
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26 August 2008 GP 10-20
f. A shallow gas kick encountered prior to setting the first pressure containment string shall
not be shut in. In such event of shallow gas flow, kill operations will immediately
commence by pumping fluid into the well at the maximum sustainable pump rate.
Floating Drilling Operations

g. Wells shall be drilled riserless until the first pressure containment string has been set,
unless:
• It is a government regulation to drill with a riser and diverter installed
• A recirculating mud system is required to drill the hole for surface casing
Prior to use of a riser to drill hole for surface casing, a documented risk assessment shall be
performed to address associated risks of riser use.
h. The rig shall be maintained in a state of readiness to move off location whilst drilling
surface hole. Where a riser is installed, procedures for well control and riser unlatch will be
established in advance.
i. All floating drilling operations carried out with returns to the installation shall be carried
out with a diverter system installed.
Bottom Founded, Barge and Platform Drilling Operations

j. A high-resolution seismic survey shall be performed for all locations. New locations shall
always be chosen to fall upon a high-resolution survey line.
k. Wells shall be drilled with a diverter system installed for all hole sections after setting
structural conductor or drive pipe and before setting the first pressure containment string.
a. The Geohazards Specialist that has produced the SHA for inclusion in the SOR should
present and participate the results of the SHA at the final design Peer Review and, or, the
Readiness to Drill Review sessions to ensure stated risks have been captured and
addressed, or mitigated, in the well programme.
b. For wells where a Geohazards Specialist has been present during the drilling of the top-
hole section, or for a well where there has been a significant variance of as-found
conditions to pre-spud prognosis, the SHA should be re-issued with an addendum attached
reviewing pre-spud prognosis to as-found drilling conditions, to ensure lessons-learnt
capture.
12. MPcp Appraise
Intent
To insure that Geohazard risks to engineering projects are clearly defined in timely and proper manner
prior to end Appraise, to allow marine Geohazards risk mitigation through field layout and, or, design
engineering to occur during Select and where deemed a requirement for quantitative risk exists.

a. An Integrated Geological Model, (Output 4, Annex C) that is integrated with the reservoir
and overburden model, shall be developed and finalised during the Appraise Stage of
MPcp that places each potential Geohazard in its correct geological context and provides a
framework for subsequent quantitative risk assessment should that be required.
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a. At this stage the final Geohazard Risk and manageability Memorandum should be used as
a management guide to define if a quantitative risk assessment should be undertaken in
parallel to risk mitigation through design on through Select.
b. While the development of the Integrated Geological model may be managed by a
Geotechnical engineer, a geological or geophysical site investigation specialist should be
fully involved in its delivery. However upon completion of this the MPcp Appraise stage,
further management of Geohazard risk will be the prerogative of Geotechnical
Engineering.
c. Upon completion of the development of the Integrated Geological model a Peer Review
(Annex D) should be organised by SPA. Attendees should include the MGTA, GESeTA
(or their delegated deputies), and geohazard specialists that have not been involved directly
in project delivery. The Peer Review should provide the SPA and Project Line
Management with a definitive steer that all significant geohazard risks to project delivery
have been identified and reviewed, and that risks have been placed in their correct context.
d. A memorandum should be issued to Project Management on completion of the Peer
Review, countersigned by the MGTA and GESeTA, or their delegates. The memorandum
shall include a final update of the Standardized Geohazard Risk Pictogram and Geohazard-
Risk vs. Current Manageability cross-plot and that shows the final level of defined
geohazard risk for the project. For projects where the final level of geohazard risk still
exceeds 16 a quantitative geohazard risk assessment should be undertaken during Select.
13. Satellite Exploration and Drilling Renewal
Intent
To ensure that when drilling activity restarts in an area, be it mobile based satellite exploration or
appraisal, or renewal of platform drilling, previous experience and knowledge is recaptured, data
quality are verified and validity of pre-existing analyses are reviewed.

a. An SHA shall be reviewed and re-issued for any well cluster, template or drilling platform
where there has been a hiatus in drilling operations of greater than two years, or where the
shallow casing plan, has been amended e.g. deepening of a casing shoe.
b. A review shall be undertaken for an SHA for any well that has been shelved for a period of
greater than a year to ensure: surface location, trajectory, target, or drilling plan has not
changed and the SHA contents remain valid. Where changes are identified an MOC
process should be applied.
a. For areas where there has been either a forced programme hiatus (e.g. well shelved or
curtailment of platform drilling) or a renewal of drilling is being undertaken to undertake
exploration or appraisal of satellite target opportunities, the validity of pre-existing site
investigation data should be carefully reviewed against regulatory requirements and the
OSIM framework.
b. Previous marine geohazard lessons learnt from activity in the area should be compiled.
Previous practitioners that have been responsible for the area should be asked to review the
lessons learnt capture to ensure key learnings have not been overlooked.
c. In the case where a jack-up rig is to be brought alongside a production platform to
facilitate restart of drilling operations, a Geotechnical Engineer should be consulted upon
the compatability of the rig with the platform’s foundations.
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Page 24 of 41
26 August 2008 GP 10-20
Annex A
Fundamental Marine Geohazard Risk Evaluation
During the Exploration Pre-Access evaluation, or immediately upon Access to a new offshore
exploration area the MGTA, or delegated deputy, should produce a memorandum that sets out
the fundamental marine geohazard risks faced within the area and the current perception of their
manageability.
This will be reported in a brief Memorandum and shall provide initial guidance towards SPU
Exploration Management on the required effort, or spend, that shall be required in supporting
initial wildcat drilling within the licence area.
The risk fundamentals and manageability shall be updated and reviewed periodically, as
indicated in the Practice above, to indicate the general health of the geohazards works
undertaken, advancement of understanding and learning from operations. The updates shall
provide a continuing guide to local management of the risk imposed on their operations and,
therefore, the ongoing level of effort required to minimise risk exposure.
The use of a uniform cross plot of Marine Geohazard risk vs. Current Manageability will allow
presentation to Senior Management of the relative risk faced by different assets within the BP
portfolio compared to their own.
A.1. The Geohazard Risk Pictogram
The Geohazard Risk Pictogram provides a simple manner in which to gauge, and communicate,
risk as well as the general health of the database which is available for evaluation of natural
geohazards.
Risk totality is defined on a spreadsheet defined pentagonal plot. Four of the axes of the
pentagon are defined by natural site properties and one by database quality.
The four natural site properties are: Shallow Structural Complexity, Regional Seismicity,
Recent Deposition Rate, and Shallow Hydrocarbon Presence. Each can be interlinked to drive
generic issues of site investigation concern. Some risk issues, for example Shallow Gas, may be
linked directly to just one axis – albeit that structure and deposition rate might increase potential
risk through column height and presence of overpressure, itself linked to shallow deposition
rate. Other issues, for example slope stability risk, may be thought of being a complex
relationship of risk from all four axes. Thus, although outwardly simple, it is hoped that the
approach will rapidly indicate fundamental risk level.
The value for each axis is spreadsheet defined on the basis of comparison to the following
qualitative or quantitative statements. A low value indicates Low fundamental risk.
A.1.1 Shallow Structural Complexity

Complexity is to be defined on the basis of a review of the available in-house seismic database
covering the basin, fairway, licence, or prospect area under consideration:
Output Risk Risk Descriptor

Value
1 Planar seabed. Horizontally, or gently, dipping sediments, no

apparent faulting in shallow section.
Example: Northern North Sea, UK or Norway.
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2 Planar or gently dipping seabed above gently warped or folded

section. No visible faulting in shallow section.
Example: West of Shetlands Deepwater, UK.
3 Seabed dipping, incised with minor erosional features, or with

recent depositional features. Shallow overburden folded and, or,
faulted. Occasional faulting reaching close to seabed.
Example: Ravenspurn, Southern North Sea, UK.
4 Increasingly complex seabed showing indications of active

"recent" geological processes or hazards. Numerous significant
faults in shallow section effected by "tight" folding or by
occasional diapiric piercement structures approaching seabed
and possibly affecting it through uplift or faulting.
Example: Block 18, Angola.
5 Distorted seabed affected by significant faulting, major seabed

failure effects, diapiric elements and/or recent depositional
events. High degree of structural complexity defined locally by
steep dips and a heavily faulted section. Mobile salt or mud
diatreme effects further complicate the section and impact on
imaging quality.
Example: ACG, Azerbaijan.
A.1.2 Regional Seismicity

Regional Seismicity is defined from descriptors set for “Seismic Zone” within the ISO
Petroleum and Natural Gas Industries – Specific Requirements for offshore structures, Part 2:
Seismic Design Procedures and Criteria (Reference: BS EN ISO 19901-2: 2004, page 11).
Whilst initially the descriptors developed were qualitative, it was agreed with the Senior
Advisor for Seismic Hazard that use of the ISO definitions allowed direct comparison to
industry practice. Additionally the standard defined risk in a five level system allowing direct
transfer into the scoring system defined here.
The values in the table refer to the definition of the area’s 1,0s Horizontal Spectral Acceleration,
Sa,map(1,0) and can be drawn from the worldwide seismic maps in Annex B of the ISO
Standard.
The output Risk Value is the “Seismic Zone” level (0-4) plus one to give the levels below (1-5).

Value
1 Sa,map(1,0) is <0.03g
Example: Gulf of Mexico, USA, or Blocks 18 or 31, Angola.
2 Sa,map(1,0) is 0.03g to 0.1g

Example: West Nile Delta, Egypt.
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3 Sa,map(1,0) 0.11g to 0.25g

Example: Caribbean Sea, Colombia.
4 Sa,map(1,0) 0.26g to 0.45g

Example: Southern Caspian Sea, Azerbaijan.
5 Sa,map(1,0) >0.45g
Example: Offshore Philippines.
A.1.3 Shallow Deposition Rate

Maximum Deposition rate should be measured from seismic data and averaged over the upper
1000m of overburden. On large, uplifted structures maximum deposition rate should be looked
at off structure and the maximum value utilized.

Value
1 Less than 150m or 500’ /million years
2 150-300m or 500-1500’ /million years
5 Greater than 900m or 3000’ /million years.
A.1.4 Shallow Hydrocarbon Presence

Shallow hydrocarbon presence can be assessed from a variety of data sources at the entry phase.
Mainly however this would expect to be reviewed on the basis of the existing seismic database
that is available in-house covering the basin, fairway, licence or prospect.
In addition to this however other relevant sources of information should also be considered:
geochemical sampling studies, satellite slick information, offset well histories from relevant
nearby licence areas, and academic publications.

Value
1 No evidence of seepage or direct hydrocarbon indicators (Bright

spots, dispersion, chimneys etc.) in the shallow section.
Temperature/pressure conditions insufficient for hydrate
formation.
2 Various direct hydrocarbon indicators in shallow section and up

to seabed. No direct calibration however. Temperature and
pressure conditions for hydrates may exist but no direct
evidence to support presence.
3 Indications on seismic of seabed seepage but uncalibrated,

numerous shallow direct hydrocarbon indicators that support
Page 27 of 41
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shallow hydrocarbon presence, evidence for suggesting BSRs

present and pressure and temperature conditions correct for
hydrate formation.
4 Indications on seismic of seabed seepage, truthed by sampling,

numerous shallow direct hydrocarbon indicators that support
shallow hydrocarbon presence and some offset well data to
support shallow hydrocarbon presence, evidence for palaeo-
mud diatremes, BSRs may be clearly present and pressure and
temperature conditions correct for hydrate formation.
5 Seabed seepage, truthed by sampling, proving presence of

active gas and oil seeps, tar mats and hydrates proving
pressure/temperature conditions correct, shallow direct
hydrocarbon indicators that support shallow hydrocarbon
presence. Offset well data support active shallow hydrocarbon
which has resulted in drilling issues, active mud volcanoes at
seabed.
A.1.5 Database Quality

Database quality is defined on the basis of the entire spectrum of relevant data that is available
to define shallow conditions and that ultimately will be used to develop an integrated geological
model.
Although data early in the process life can initially be considered to be dominated by seismic
data, the database should also consider the quality of all relevant data sources to include
hydrographic, geotechnical engineering, wells, remote sensing imagery, and academic and
consultant publications and reports.

Value
1 Quality exploration 3D data image and amplitude response up

to and including the seabed. Offset, or overlying shallow
geophysical data, available relevant offset geotechnical data,
well data, and numerous relevant supporting academic
publications.
Example: New Gulf of Mexico, USA, or North Sea, UK or
Norway, Lease.
2 3D cover processed to image deeper section, leaving shallow

section poorly imaged and/or with poor amplitude response.
Older 2D regional data assists clarification of issues. Some
offset well and/or overlying site investigation data of variable
quality. Numerous academic studies discuss key risks and
provide further assisting data.
Example: West Nile Delta, Egypt.
3 No 3D cover. Good quality 2D seismic regional grid at 1.0km

spacing or better that images the shallow section well and
indicates complexity and potential issues. Area may have been
previously licensed, so some directly relevant site investigation
Page 28 of 41
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or well data may be available although quality is inadequate.

Some relevant publications.
Example: Nam Con Son Basin, Vietnam, at entry.
4 No 3D seismic cover. Regional 2D exploration cover gives fair

idea of shallow section variability. No site investigation data
close by but some valid nearby non-operated experiences.
Some useful academic publications and data that highlights
potential issues.
Example: Ormen Lange, Norway upon award
5 No 3D Seismic Cover. Sparse spaced regional 2D exploration

cover that ineffectually images the shallow section. No site
investigation data in area. General paucity of academic
publications on the area.
Example: Sirte Deep, Libya, on entry.
Geohazard Risk Summary
A.1.6 Pictogram Display Shallow Image / Existing Database

Quality
Once the values of the five 5
vertices of the pictogram have

4
3
been defined the values can be 2
plotted directly within the Shallow Hydrocarbon Presence

1
Shallow Structural Complexity
spreadsheet and the 0
fundamental Geohazard Risk

Area is output coloured red. The
greater the output red area – the
greater the perceived Shallow Deposition Rate Regional Seismicity
fundamental geohazard risk.
A.1.7 Fundamental Geohazard Risk

The Fundamental Geohazard Risk quotient is the sum of the five fundamental geohazard risk
element vertices defined from an examination of the above descriptors for the area in question
and plotted in the pictogram as illustrated here.
Thus in the example shown, the fundamental geohazard Risk quotient value is 20, a high value.
Where the fundamental Geohazard Risk value at the end of Appraise remains at a value greater
than 16 then Quantitative Risk Assessment of the key geohazards risk elements defined in the
Geohazard Risk Source Spreadsheet (Annex C.1 below) will be required during MPcp Select.
25
6 A.2 The Geohazard Risk Cross Plot

Fundamental Geohazard Risk
5
4 Prospect Key To allow different projects to be compared for
1. Project Z management purposes the output value for
2. Project Y
1 3 3. Project X Fundamental Geohazard Risk should be cross-
2 4.
5.
Project A
Project B
plotted on a standard Boston Square basis where
6. Project C the “Y” axis of the display is Fundamental
Geohazard Risk between 0 and 25 and the “X”
7 axis is a qualitative assessment of Current
0
Current Geohazard Manageability Assessment
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Geohazard Manageability as shown in the example here.

Geohazard Manageability is the current perceived impact that Geohazards may have on design,
or choice of location, of wells and/or facilities.
In an area of high fundamental geohazard risk and with little experience within the area or
equivalent global analogies to apply, or where drilling or development difficulty has been
proven to be high, then manageability must be considered to be low (plotted to the left).
In an area where fundamental geohazard risk is low, or where there is a large amount of offset,
or relevant analogue experience to indicate that geohazard risk can be managed with little effort,
then manageability must be considered high (plotted towards the right).
The output position of the Licence, Prospect, or Field being studied should be cross-plotted
against a representative spectrum of other projects to be able to properly provide an illustration
of comparative relative risk.
At the Entry Stage of the process, and thereafter when revisited, an indication of the likely
vector and quantity of potential likely move that further study may bring should be defined for
the area under study by addition of an arrow, as shown in this example for Project Z.
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Annex B
Geohazard CRS Map Construction
B.1 General
Geohazard Common Risk Segment (CRS) maps should be produced in a standardised manner to
ensure comparability from Project to Project. The techniques used to combine the various layers
to produce the Geohazard CRS map should not be dissimilar to the processes used to develop
Exploration CRS maps.
Wherever possible the use of a GIS should be used to allow the various subject layers to be
combined, or separated, for use as a combined CRS or separate risk zonation maps.
B.2 CRS Map Colours
Only three colours are acceptable for use on a CRS map: Green (Negligible - Low), Yellow
(Moderate) and Red (High) to define variance of geohazard risk across the study area.
Colours should not be subdivided, shaded, or made semi transparent to express subtle user
perceived nuances of possible risk or uncertainty. In combining layers a conservative approach
shall always be used such that the worst level of risk (Red) always dominates. Therefore the
following example logic trains shall always be used:
Red: Combined with any number of other levels of green and / or yellow shall
remain red.
Yellow: Combined with any number of other levels of green shall remain yellow.
Green: Shall require that all component layers are green.
B.3 CRS Map Component Layers
The following layers shall be produced and combined to produce the fundamental colour
background of the Geohazard CRS map.
B.3.1 Seabed Slope Angle

Slope angle risk component shall be defined in the following manner from the regional seabed
morphology defined from the available bathymetric (public or purpose acquired location
specific survey) database, seabed seismic pick (project or prospect wide 3D bin pick or gridded
regional 2D pick). The highest quality data should always dominate the categorization process
(e.g. high resolution, small bin, multi-beam data, over 3D seismic seabed pick, over published
regional bathymetry charts):
Red: >8 degree slope angle.
Yellow: >3 to 8 degree slope angle.
Green: 0 to 3 degree slope angle.
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B.3.2 Slope Stability Stand-off Zones

In MPcp Appraise, where adequate information (geotechnical boreholes, soil analysis, pore
pressure measurements, 2D Slope stability modelling etc.) has been gathered and integrated to
be able to quantitatively estimate stand-off distances from slope failure headwalls or failure
zones (e.g. ACG Project, Azerbaijan), the defined areas shall be coloured as follows:
Red: The area within the slope stability stand-off zone (i.e. the region between the
top of an existing headwall scarp and the calculated stand back distance
behind it, or the calculated failure point on a critical slope and the calculated
safe stand back distance behind the estimated point of failure), and zones of
critical energy [facility dependant] run-out for any calculated failure zones.
Yellow: The area between the safe-stand back distance and any quantitative error
fringe determined further back behind the defined safe-stand back distance,
and zones of non-critical energy [facility dependant] distal run-out for any
calculated failure zones.
Green: All areas outwith the above determined areas.
B.3.3 Seabed Environmental Constraints

Seabed environmental constraints should be defined on the basis of purpose acquired
hydrographic sonar results (high resolution sonar or multi-beam backscatter data), 3D seismic
seabed amplitude variation, direct visual inspection results by ROV, lander, or drop camera
stills, seabed samples, local regulatory authority defined exclusion zones (e.g. Gulf of Mexico,
Flower Garden Banks etc.), or published localities of sites of special scientific interest.
Red: Defined extent of any Local Regulatory Body defined exclusion areas or
published site of special scientific interest; the extent of a seabed
hardground calibrated by ROV or still photography to be a live
chemosynthetic or cold coral reef; or an uncalibrated seabed bright that is
suspected as being a chemosynthetic or cold coral mound (hardgrounds shall
be defined on the basis of: high sonar or multi-beam backscatter values, or
anomalously high seabed amplitude pick from 3D seismic); or the extent of
a sensitive seabed area classified as a potential fish spawning ground
(defined by a subject matter expert on the basis of sonar backscatter, photo
calibration and/or grab sampling).
Yellow: Legal stand-off zones to any Local Regulatory Body defined exclusion
zones, regulation required stand-off to any proven hardgrounds (yellow halo
around “Red” zones), areas calibrated by visual inspection not to be live or
active reefs, or areas where interpretive doubt exists.
Green: No regulatory stipulated areas or stand off zones, no definable feature
present on hydrographic or seismic data, or the features present can clearly
be interpreted to be due to other causes, or direct sampling, or visual
inspection, has proven the absence of chemosynthetic, cold water coral
growth or conditions that might be defined as sensitive (e.g. fish spawning
grounds).
To assist in definition of potential sensitive areas the BP Seafloor Hardground &
Chemosynthetic Community Interpretation Guide Points should be used. The guide points
should be used to study specific areas of concern as Geohazard CRS mapping effort moves from
the fairway, or licence, level to the Prospect and into Project level.
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B.3.4 Archaeological Features or Munitions Disposal Zones

Known or suspected archaeological features, regulatory defined stand off zones, identified
munitions or directly defined munitions disposal zones should be recognised as potential
constraints to well location choice or field layout from the start of the Geohazards process and
refined as the database is developed.
Red: Published and verified wreck site(s) and regulatory stand-off radius, or
munitions dumping ground scatter zone identified with high degree of
certainty on sonar data or verified by visual inspection.
Yellow: The extent of any published munitions dumping zone until cleared by
acquisition of high resolution sonar or visual verification, suspect sonar
contact trails un-verified by visual inspection, uncertainty zone around
published (e.g. Admiralty wreck list) approximate wreck [sinking] positions
unverified by survey data.
Green: Areas where there is an absence of any published munitions dumping
ground boundary, or no reason from available data to suspect the presence
of disposed munitions, wrecks, or archaeological features.
B.3.5 Shallow Gas Anomalies

At the fairway or licence wide CRS generation level, Shallow gas presence should be defined on
the basis of extracted amplitude anomalies on a 100ms layer-cake interval from 3D data from
the seafloor down to an equivalent level of 200m below the expected setting depth of the first
pressure containment string.
As CRS maps are refined, as the process proceeds towards prospect drilling, the anomaly
bounds should be updated to represent key intervals or horizons identified in detailed
interpretation of 3D and purpose acquired HR or UHR seismic data.
Regardless of the detail of effort, the following categorizations should always be applied:
Red: Extent of any amplitude anomaly for a layer, or zone, where the picked, or
extracted, amplitude level exceeds five times the level of background, unless
the anomaly in question has been drilled, open hole, without any flow
resulting.
Yellow: Extent of any amplitude anomaly for a layer, or zone, where the picked, or
extracted, amplitude level exceeds 2.5 times the level of background, but
does not exceed five times background, or an anomaly where the amplitude
does exceed five times background but that has been drilled, open hole,
without any flow being observed.
Green: All amplitude anomalies, or amplitude variation, for the event, or interval, in
question are less than 2.5 times background level or are clearly related to
non gaseous causes: lithological contrasts or tuning.
To assist in definition of potential shallow gas anomalies the BP Shallow Gas Interpretation
Guide Points. The guide points should be used to study specific levels and, or, areas of concern
as Geohazard CRS mapping effort moves from the fairway or licence level to the Prospect or
Project level. The BP Shallow Gas Interpretation Guide Points should always be used on a well
trajectory specific risk assessment.
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B.4 Superimposed Line Detail
The following features can be superimposed upon the colour background of the Geohazard CRS
map to allow development of the thematic nature of the map and to provide some interpretive
background.
B.4.1 Seafloor Geomorphological Elements

Such detail may include significant geomorphological elements not included in the colour
zonation developed above but that that may have a significant impact on the choice of well
location or facility lay-out. Features may include but not be limited to pockmarks, furrows,
expulsion zones, collapse features, mud volcanoes, sand-waves, mega-ripples, slope failure head
walls, slide zones, failure run outs or slump toes, scours, areas of erosion or truncation, rock
exposure, etc.
Line usage to define such detail should be clear, consistent and fully defined on the key.
B.4.2 Seafloor or Shallow Faults

Faults that intersect, or are within foundational impact distance below, the seabed should be
shown as lines with peck marks to show the direction of throw and style of the faults. Depths
below seabed to the top of the fault should be shown where the faults are buried.
The only exception to this is if the fault has been defined, by specialist study, to be a significant
seismogenic fault that might effect the choice of location for a well or facility. In such a case the
trace of the fault should be marked in black and the defined stand-off zone should be defined in
Red.
B.4.3 Shallow Soils Provinces

Shallow soil province boundaries should generally not be superimposed upon a Geohazard CRS
map.
The only exception to this rule is if the presence of a key soil unit presents a significant
limitation on choice of surface facility for a development – such as the presence of a soft soil
infilled channel (e.g. Witch Ground Formation, North Sea) or the seabed sub-crop of a hard rock
formation (e.g. Corallian Limestone, Hyde and Hoton Fields, North Sea). In such a case the
edge of the presence of the soil, or rock, unit should be defined and a clear reference provided to
a supporting Soil Province Map or an Isopach Map of the unit in the key.
B.5 Chart Commentary
A Geohazard CRS map should include a panel of commentary on specific geohazard risk issues
that cannot be simply captured by a colour zonation or line work as described above.
Such issues may include, but not be limited to; regional Shallow Water Flow Risk, Regional
Seismicity Risk, Slope Instability and Sensitive Soils.
Information, that might be drawn directly from the project’s Geohazard Risk Source
Spreadsheet, should be presented in a tabular or spreadsheet form in three columns: 1.
Geohazard issue, 2. Description and potential impact of issue, and 3. Generic Risk Level (High,
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Medium, or Negligible – Low). The background of each risk row should have a colour
background that reflects the generic risk level (Red, Yellow, or Green).
B.6 Management of Change
The output CRS map and each individual component layer used to build the map should have a
Management of Change (MOC) panel that records the update history of the composite display
and individual component layers used to derive the final presented form. This should be
achieved through the use of an embedded MOC revision panel.
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Annex C
Integrated Geological Model
C.1 Start Point
At the start of MPcp Appraise a Geohazard Risk Source Spreadsheet (GRSS) should have been
developed that defines all credible sources of possible Geohazard risk that might affect the
development area, their cause, and likely engineering impact.
Once developed the GRSS should be used to develop an integrated work plan (data acquisition,
tests, analyses, studies, etc.) that will support characterization of the final defined risk for each
risk element identified.
The work identified should characterize, from the geological standpoint, the significant items of
geohazard risk in an integrated manner. All elements of risk should have been closed out, or
their outstanding impact clearly defined, by end of MPcp Appraise as part of an Integrated
Geological Model.
The GRSS should be used by the Site Investigation Project Manager to sense check the progress
and direction of the work of the Integrated Site Investigation team as the work progresses. The
GRSS should also be kept up to date and used to communicate progress to Project and SPU
management on the diminution of risk – if such is being attained.
C.2 Final Desired Outcome
At the end of MPcp Appraise an Integrated Geological Model shall have been developed, and
reviewed, that describes the area, and addresses all likely geohazard risks identified at the start
of Appraise in the GRSS, and that were considered to potentially have an affect on field layout
or drilling and facility design.
To this end, the Integrated Site Investigation Team shall have developed a calibrated local
geological model: that explains the geological development of the area, the drivers behind the
geological processes that have left the area in its current condition/appearance, and explains
how the area is expected to evolve over life of field.
Each GRSS listed geohazard risk element should be clearly defined: as initially risked, the
individual work elements undertaken to define the final output [residual] risk from each
element, and the final output residual risk and its effect on development layout or design: e.g.
stand off zones etc..
The risks should be displayed spatially in the Project’s Final Composite Geohazard CRS map
for field layout design.
C.3 Model Review
In the Peer Review (Annex D) at the end of MPcp Appraise the final developed Integrated
Geological Model shall be reviewed.
The Project Site Investigation Team shall present GRSS and Geohazard CRS Map from the start
of Appraise, the developed Integrated Geological Model, and the final defined impact of any
Geohazard risk element on ensuing risk over life of field by presenting the final updated GRSS
and Geohazard CRS Map.
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C.4 QRA
Quantitative Risk Assessment (QRA) does not need to be undertaken in MPcp Appraise.
However areas where QRA may be required in MPcp Select must have been identified at end of
MPcp Appraise and these should be agreed in the End Appraise Peer Review, and signed off by
the two SeTAs (if not present at the Peer Review).
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Annex D
Marine Geohazard Peer Review Terms of Reference
D.1. Review Team (minimum requirements):
• Leader (needs to be a Senior Site Investigation or Geotechnical Engineer)

• The MGTA and GESeTA or their delegated deputies (may be the Review team leader for
example).
• At least one reviewer from outside the asset (to insure transfer of lessons learned both to
and from the team)
• Experienced practitioners in the integration of geophysical/geological site investigation
material with Geotechnical Engineering data and the types of studies that may be
undertaken to integrate such data to answer specific concerns. The skills mix will depend
very much upon the key risk types under evaluation.
• Note: If one individual fulfils the combined requirements above, then it is not required to
have multiple team members. In general however the more complex the setting the more
reviewers will be required and the more critical that the MGTA and/or the GESeTA are
present.
D.2. Site Investigation Project Team Participants:
• Single Point of Accountability (SPA) for the delivery of the Integrated Geological Model
that categorizes Geohazard risk.
• Site Investigation Specialist(s) directly involved.
• Geotechnical Engineer(s) directly involved.
• Consultants used for [key] Specialist Studies.
• Appraise Project Manager (at start of review to set the scene and finish of the review to
directly hear feedback)
• Relevant Project Engineers (Facilities, Pipelines, Drilling etc.)
D.3. Objectives:
The primary objective of the review is to determine if the developed Integrated Geological
Model has properly addressed and classified risk from all reasonable potential Marine
Geohazard risks that may impact upon the Prospect/Location.
As a minimum the Peer Review Team should answer the following questions:
1. Have appropriate methods and data been applied to develop the integrated geological
model?
2. Are there any gaps in the database used that leaves significant uncertainty over the
results presented?
3. If there are perceived gaps, what actions need to be taken?
4. Have all reasonable and relevant sources of Geohazard risk been identified and
analysed?
5. Have appropriate analogue projects been identified and used?
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6. Were the analogues properly analyzed to assist in constraining and comparison of

output risks?
7. Are the stated Geohazard risks consistent with the integrated geological model and data
presented and appropriate known analogues?
8. Have uncertainties been properly described for all relevant potential sources of
Geohazard?
9. Is any additional work required before the project proceeds into MPcp Select?
D.4. Desired Outcomes
• Identification of mandatory additional work that needs to be completed before the project
proceeds to MPcp Select.
• Assurance that the work performed meets the standards of the BP Engineering Technical
Practice on Marine Geohazards, is consistent with approved BP workflows, and meets the
required technical level to enter MPcp Select.
• Definition of whether Quantitative Risk Analysis of specific sources of Geohazard risks will
be required to be undertaken in MPcp Select.
• Documentation of the review and any outstanding Major Accident Risk areas that need to
be expressed to relevant business leaders.
• Update of the final position of the project on the Geohazard Risk vs. Manageability cross-
plot.
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26 August 2008 GP 10-20
Annex E
Administration
E.1. Administration and Authorisation
Administration and Authorisation

Administration and authorisation responsibilities for this Practice are:
Custodian: The Marine Geohazards Technical Authority
Maintainer: The Marine Geohazards Technical Authority
Adjudicator: The Vice President Geoscience and Subsurface Description under
Delegation from TVP Subsurface and Wells and the Head of Discipline
Drilling & Completions under delegation from the TVP Drilling &
Completions.
The Custodian is responsible for confirming the accuracy and integrity of content and proposed
changes to the Practice.
The Maintainer is responsible for the upkeep and continued integrity of the Practice, including
regular reviews and audits.
The Adjudicator is responsible for authorising and approving changes to the Practice.
Interpretation
Questions of interpretation should be directed in writing to the custodian of this Practice for the
purpose of clarification.
Changes and Amendments
Any suggested changes or amendments to this Practice should be forwarded to the document
custodian along with the reasons for the change.
All suggestions should be acknowledged and, if rejected, the reasons given for their rejection.
Accepted changes should be administered through the document change control system
employed by the Document Control Management System (DCMS).
Document Control and Review
The Practice shall be held and controlled on the DCMS.
This Practice is subject to regular review and also to review whenever circumstances dictate. All
reviews, regular and otherwise, shall be initiated by the Custodian.
E.2 Auditing, Compliance and Deviation
Auditing and Compliance

Monitoring adoption of this Practice and reporting on implementation and progress on meeting
targets shall be locally owned and included as part of the annual self verification process for
each Strategic Performance Unit (SPU) and Functional Unit.
BP businesses that are within the scope of this Practice shall adopt or modify their procedures
and practices to conform to the Minimum Requirements described in this document.
In the event of a conflict between this Practice and a relevant law or regulation, the relevant law
or regulation shall be followed. If this Practice creates a higher obligation, it should be followed
as long as full compliance with the law or regulation is also achieved.
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Deviation from Minimum Requirements

A decision not to implement these Practices by an SPU, or for a given field or project, requires
that a risk assessment be conducted and formally peer reviewed.
Any risk assessment that results in the decision not to apply this Practice shall be formally
justified, recorded, and authorised by the relevant SPU Leader or their delegated nominee.
Page 41 of 41

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Document No.

Marine Geohazards Evaluation and

The introduction to this ETP mirrors section 17 of the revised DWOP.

• Potential presence of shallow gas

• Potential of shallow gas being abnormally pressured, if present

• Possible use of pilot hole

• Rig type and capabilities

• Kill mud requirements

• Riser or riserless configuration

1.2. Floating Drilling Operations

• It is a government regulation to drill with a riser and diverter installed

1.3. Bottom Founded, Barge and Platform Drilling Operations

What is the Marine Geohazard Recommended Technical Practice?

This Practice is intended for the use of following groups:

• Wells or Project management who require understanding of process fundamentals and

Copyright © 2008 BP International Ltd. All rights reserved.

13.2. Recommendations .................................................................................................... 23

3. Terms and definitions

The power to influence or command.

A contractual relationship includes:

• All individuals contracted directly or sub-contracted.

• All employees of companies contracted directly or sub-contracted.

b) An action to mitigate risk.

c) The power to direct (usually through authority).

Document Control Management System

Single Point Accountable

4. Symbols and abbreviations

BtBcp The D&C Beyond the Best Common Process

CoP Community of Practice, the Geoscience replacement for “Network.”

CRS Common Risk Segment

CVP Common Value Process

D&C Drilling and Completions

DCMS Document Control Management System

DWOP Drilling and Well Operations Policy (BPA-D-001)

Ecp Exploration Common Practice

GDE Gross Depositional Environment

GeoRP Geoscience recommended practice. The Geoscience equivalent of an ETP.

GESeTA Geotechnical Engineering Segment Technical Authority

GIS Geographical Information System

HoD Head of Discipline

HSSE Health, Safety, Security and Environment

MGTA Marine Geohazards Technical Authority

MPcp Major Projects Common Process

NDS No Drilling Surprises, a key strand of the BtB common process

PPFG Pore Pressure Fracture Gradient

OMS Operating Management System

OSIM Offshore Site Investigation Manual (BPA-D-005)

SeTA Segment Technical Authority

S&SI Survey and Site Investigation, a geoscience functional community of practice.

SOR Statement of Requirements, a key output of the BtB process.

SPA Single Point of Accountability

SPU Strategic Performance Unit

TAM Technical Appraisal Memorandum

TVP Technology Vice President

5.1. Requirements and Recommendations

• 'Shall' is used where a provision is mandatory.

5.3. References and Responsibilities

6.1. Minimum Requirements

7.1. Minimum Requirements