eni - well control policy manual

ARPOENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OFACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 92STAP P 1 M 6150

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used forreasons different from those owing to which it was given

TITLE

WELL CONTROL POLICY MANUAL

DISTRIBUTION LIST

Eni - Agip Division Italian Districts

Eni - Agip Division Affiliated Companies

Eni - Agip Division Headquarter Drilling & Completion Units

STAP Archive

Eni - Agip Division Headquarter Subsurface Geology Units

Eni - Agip Division Headquarter Reservoir Units

Eni - Agip Division Headquarter Coordination Units for Italian Activities

Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni -Agip Division Headquarter)

Date of issue:

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� Issued by P. MagariniE. Monaci

C. Lanzetta A. Galletta

28/06/99 28/06/99 28/06/99

REVISIONS PREP'D CHK'D APPR'D

28/06/99

ARPO

ENI S.p.A.Agip Division

IDENTIFICATION CODE PAGE 2 OF 92

REVISIONSTAP-P-1-M-6150 0

INDEX

1. INTRODUCTION 6

1.1. Purpose of the manual 6

1.2. UPDATING, AMENDMENT, CONTROL & DEROGATION 7

1.3. DRILLING CONTRACTOR'S PERSONNEL 7

1.4. SAFETY TARGETS 81.4.1. Primary Control 81.4.2. Secondary Control 8

1.5. TECHNICAL PROFICIENCY 8

2. COMPREHENSIVE WELL CONTROL PROCEDURES 9

2.1. PRIMARY WELL CONTROL 92.1.1. Drilling Programme 92.1.2. Detection OF Abnormal Well Conditions 92.1.3. Kick Prevention 102.1.4. Maximum Allowable Annulus Surface Pressure (MAASP) 112.1.5. Reduced Pump Stroke Pressure (RPSP) 11

2.2. SECONDARY WELL CONTROL 122.2.1. Kick Control Procedures (Preliminary Actions) 122.2.2. Kick Detection Procedure While Drilling 122.2.3. Kick Detection Procedure While Tripping 12

3. SHUT-IN PROCEDURE. 14

3.1. SOFT SHUT IN PROCEDURE (for LAND RIGS, JACK UPS AND FIXED PLATFORM) 143.1.1. Soft Shut-in Procedure While Drilling 143.1.2. Soft Shut-in Procedure While Tripping 15

3.2. SOFT SHUT IN PROCEDURE (Floaters) 163.2.1. Soft Shut-in Procedure While Drilling 163.2.2. Soft Shut-in Procedure While Tripping 17

3.3. POST Shut-In OPERATIONS 18

3.4. PRESSURE DATA RECORDING 18

4. STRIPPING PROCEDURE 19

4.1. OFF BOTTOM KICKS 194.1.1. Preparing To Strip-In 19

4.2. STRIPPING METHODS 204.2.1. Stripping Through Annular Preventers 214.2.2. Stripping Through Ram Preventers 214.2.3. Annulus pressure control while stripping 224.2.4. Stripping Worksheet 23

5. KILLING PROCEDURES 24

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5.1. Well Control Methods 245.1.1. Wait And Weight Method 245.1.2. Driller’s Method 265.1.3. Volumetric Method 275.1.4. Volumetric control worksheet 295.1.5. Bullheading 30

5.2. horizontal well considerations 30

5.3. FLOATING RIG CONSIDERATIONS 315.3.1. Effect Of Choke Line Length 315.3.2. Influx Removal From BOP And Riser 32

6. EQUIPMENT REQUIREMENTS 35

6.1. BOP STACK SYSTEMS 356.1.1. Land Rigs, Jack-Ups And Fixed Platform 356.1.2. Floating Rigs 36

6.2. BOP CONTROL SYSTEM 376.2.1. Land Rigs, Jack-Ups And Fixed Platform 376.2.2. Floating Rigs 38

6.3. CHOKE MANIFOLD 39

6.4. INSIDE PIPE SHUT-OFF DEVICES 39

6.5. MUD GAS SEPARATOR 40

6.6. diverter equipment 40

6.7. AUXILIARY EQUIPMENT 42

7. CASING AND BOP EQUIPMENT TESTS 43

7.1. GENERAL PROCEDURES 437.1.1. Test Recording 43

7.2. BOP EQUIPMENT TESTS 447.2.1. Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests 447.2.2. BOP Tests After Installation 447.2.3. Surface BOP Testing Procedures 44

7.3. FLOATing RigS 457.3.1. BOP Tests During And After Installation 457.3.2. BOP And Seal Assembly Tests After Setting Casing 457.3.3. Routine BOP Tests While Drilling 467.3.4. Routine Subsea BOP Testing Procedures 46

7.4. bOP TESTing frequency 467.4.1. BOP Test Durations 467.4.2. BOP Function Tests 477.4.3. BOP Operating Equipment Tests 477.4.4. Kill lines, Choke Lines And Choke Manifold Tests 477.4.5. IBOP, Cementing Manifold, Pumps And Standpipe Manifold Tests 47

7.5. Casing Tests 48

7.6. OTHER TESTS WHILE DRILLING 48

8. BLOW-OUT PREVENTION DRILLS 49

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8.1. FAMILIARITY DRILLS 498.1.1. Shut-In Drills 498.1.2. Choke Manipulation Drill 50

8.2. EMERGENCY ‘ON-THE-RIG’ DRILLS 508.2.1. Potential Fire On Well And Rig Abandonment Simulation 508.2.2. H2S Drill 508.2.3. Abandon Rig 51

8.3. WELL CONTROL DRILLS 518.3.1. Pit Drills 518.3.2. Trip Drills 528.3.3. Trip Drill With Drillpipe In The BOP Stack. 528.3.4. Trip Drill With Drill Collar Or Tubing In The BOP Stack. 52

8.4. Accumulator Drills 53

8.5. Diverter Drills 53

8.6. Drill FREQUENCY AND Response TIMES 548.6.1. Drill Frequency 548.6.2. Timing 55

9. SHALLOW GAS 56

9.1. SHALLOW GAS INVESTIGATION 56

9.2. PRIMARY WELL CONTROL 57

9.3. RECOMMENDED DRILLING PRACTICES 579.3.1. General Practices 579.3.2. Logging 599.3.3. Losses 599.3.4. Cementing Operations 599.3.5. Drilling Procedures 60

9.4. DIVERTER SYSTEM OPERATIng PROCEDURES 619.4.1. Diverter System 629.4.2. Diverter Test (before start of operations) 649.4.3. Diverter Procedure 64

10. H2S DRILLING PROCEDURES 65

10.1. Emergency Safety Plan 65

10.2. DUTIES OF PERSONNEL 6610.2.1. Manager Or OIM 6610.2.2. All Personnel 6610.2.3. Eni-Agip Drilling Supervisor 6610.2.4. Drilling Contractor's Toolpusher 6710.2.5. Driller 6710.2.6. Mud Engineer 67

10.3. OPERATING CONDITIONS AND PROCEDURES 6710.3.1. Condition 1 - Pre Alarm 6710.3.2. Condition 2 - Alarm 6910.3.3. Core Recovery In Presence Of H2s 7010.3.4. Well testing in presence of H2S 70

10.4. Emergency Condition 7310.4.1. Emergency Operating procedure 74

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10.5. ACTIONS TO TAKE FOR THE CONTROL OF AN EMERGENCY 75

10.6. EMERGENCY TEAM 75

10.7. DELIMITATION OF THE POLLUTED AREA (onshore) 76

10.8. PERSONNEL TRAINING 7610.8.1. Safety Meeting 76

10.9. H2S Prevention drills 7710.9.1. Alarm Drills 7710.9.2. Emergency Drills 7810.9.3. Drill Frequency 78

10.10. H2S DETECTION SYSTEM 7810.10.1. H2S detection in air 7810.10.2. Sensor Ranges 79

10.11. BREATHING APPARATUS AVAILABILITY 8010.11.1. Standard Equipment For All Rigs 80

10.12. CASCADE SYSTEM 81

10.13. USE OF BREATHING APPARATUS 82

10.14. ADDITIONAL safety features 82

10.15. INSPECTION/MAINTENANCE OF DETECTION/PROTECTION SYSTEMS 83

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1. INTRODUCTION

This document replaces:

STAP P 1 M 071 - WELL CONTROL POLICY FOR LAND DRILLING UNITS (Chapter 7of ‘General Drilling Procedures for Land Drilling Units’)

STAP P 1 M 6033 - WELL CONTROL POLICY FOR JACK UP AND FIXED PLATFORM(Chapter 13 of ‘General Drilling Procedures for Self Elevating MobileOffshore Drilling Units - Jack Up - and Fixed Platform’)

STAP P 1 M 047 - WELL CONTROL POLICY FOR FLOATER (Chapter 38 of ‘GeneralDrilling Procedures for Floating Drilling Unit’)

STAP P 1 M 11 - SHALLOW GAS DRILLING GUIDELINE

P 1 M 6035 - DRILLING PROCEDURES FOR OFFSHORE WELLS IN H2SENVIRONMENT

P 1 M 6039 - DRILLING PROCEDURE FOR LAND WELLS IN THE PRESENCE OFH2S

1.1. PURPOSE OF THE MANUAL

The main purpose of this Well Control Policy is to make all parties, involved in Eni-AgipDivision and Affiliates drilling and completion activities world-wide, aware of the Company’sbasic rules and procedures related to Well Control Policy issues.

Nevertheless, the policies in this manual, while being compulsory, cannot foresee all aspectsof the operations that may be encountered on the well site.

It consequently requires oneself to conform to the principles of this policy in dealing withunexpected situations different from those planned or anticipated.

Such Corporate Standards define the requirements, methodologies and rules that enable tooperate uniformly and in compliance with the Corporate Company Principles. This, however,still enables each individual Affiliated Company the capability to operate according to locallaws or particular environmental situations.

Company regulations and/or Petroleum Industry world-wide accepted practices do notsubstitute for government regulations, nor is it possible to include all of the issuedgovernmental regulations inside one Company general policy statement.

Part of the duty of Company drilling personnel operating world-wide, includes verification thatactual Company policy meets with any and all local regulations, ensuring that the moststringent of the policies or regulations between both apply.

The Drilling Contractor will issue their own ‘Operating Practices and Emergency Procedures’which shall be applicable to the Drilling Contractor's rig and equipment specifications and tomeet with the intent of Eni-Agip’s Well Control Policies.

The Drilling Contractor’s ‘Operating Practices and Emergency Procedures’ shall besubmitted to, and approved by, the Company before the contract commences.

For floating rigs, details have to be provided of the marine riser tensioning and the practicaloperating motion limits of the rig, beyond which drilling, tripping, handling BOP and testingshall be suspended.

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1.2. UPDATING, AMENDMENT, CONTROL & DEROGATION

This is a ‘live’ controlled document and, as such, it will only be amended and improved by theCorporate Company, in accordance with the development of Eni-Agip Division and Affiliatesoperational experience. Accordingly, it will be the responsibility of everyone concerned in theuse and application of this manual to review the policies and related procedures on anongoing basis.

Locally dictated derogations from the manual shall be approved solely in writing by theManager of the local Drilling and Completion Department (D&C Dept.) after theDistrict/Affiliate Manager and the Corporate Drilling & Completion Standards Department inEni-Agip Division Head Office have been advised in writing.

The Corporate Drilling & Completion Standards Department will consider such approvedderogations for future amendments and improvements of the manual, when the updating ofthe document will be advisable.

1.3. DRILLING CONTRACTOR'S PERSONNEL

As clearly stated in Eni-Agip’s Contracts, all Drilling Contractor personnel shall be proven tobe competent and able to act with diligence in a safe and workmanlike manner according togood Oilfield Practices.

Within the terms of the Well Control Policy, this means that each crew shall be completelyfamiliar with the installation, operation, care and maintenance of every item of equipment withregard to the mud system, trip tank, surface and choke manifold, mud/gas separators, valves,instruments, pressure gauges, indicators, volume meter, BOP’s and their operating units.

Key personnel such as Rig Managers, Toolpushers, Tourpushers, Drillers, Assistant Drillers,Subsea Engineers shall have the fundamental theoretical knowledge on kick and blow-outcontrol techniques and also hold a current Well Control Certificate issued by an accreditedindustry training institute recognised by Governmental bodies and the Company.

Furthermore, it is required that each member should be familiar with every item of equipmentused in well control. The minimum personnel knowledge and capabilities required for a crewmember to be considered competent is:

• To have sufficient knowledge of all the equipment in order to be able to determinewhen operating functions are not working properly, and consequently, take allnecessary remedial actions to reinstate full functionality.

• To have sufficient knowledge of operating procedures in order to be able to reactin due time, understanding completely what is occurring.

• To be able to correctly interpret the various abnormal situations and take theappropriate remedial steps of action.

• Carry out basic calculations, and use the results in order to safely manage anyoccurrences.

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1.4. SAFETY TARGETS

Maintaining the well under full control at all the times shall be the main safety target. This is tobe achieved by applying appropriate principles and techniques aimed at providing thefollowing well control phases:

1.4.1. Primary Control

During drilling operations, a mud hydrostatic pressure will be used to exceed or overbalancethe formation pressure and prevent the formation fluids from being able to enter the wellbore.

1.4.2. Secondary Control

When primary well control has been lost or compromised and formation fluid enters thewellbore, the blow-out prevention equipment and procedures will be brought into action inorder to re-establish primary control and safe operating conditions.

1.5. TECHNICAL PROFICIENCY

The primary concern of all parties involved in drilling hydrocarbon wells is to maintain fullcontrol of formation fluids at all times, preventing their migration into the wellbore. Whenoccasions do occur when formation fluids enter the wellbore, proper actions must beimplemented to control the influx and restore safe operating conditions. The basic rules,practices and techniques used to achieve these goals are found from:

• Well Control Policies.• Local regulations.• Drilling programme.• Operational rules and emergency procedures.• Methods and means to permit an early detection of abnormal situation.• Inspections, tests and maintenance of prevention equipment.• Personnel theoretical knowledge, training and skill.

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2. COMPREHENSIVE WELL CONTROL PROCEDURES

2.1. PRIMARY WELL CONTROL

2.1.1. Drilling Programme

Primary well control is at first achieved by the implementation of a properly prepared drillingprogramme, based on pore pressure predictions ( Refer to the Overpressure EvaluationManual). This information should allow the proposed well targets being reached, protectingpersonnel, rig equipment and Company assets.

The Company shall provide data and information derived from:

• Wells previously drilled in the same field or in the same area• Seismic surveys• Geological information

This data shall be analysed in order that an appropriate drilling programme can be compiled.

The Drilling Contractor shall receive a copy of the drilling programme in advance so as to beready to make rig personnel familiar and acquainted with the risks of the variant well drillingoperations involved.

Primary well control depends mainly on the use of correct mud weights, proper operatingpractices implemented, as well as the accuracy and control of constantly gathered data;These data should be correctly interpreted and timely reported.

‘Drilling for kicks’ is not permitted, i.e. ‘underbalance’ drilling operations and definitelynever allowed on wildcats under any circumstances. Underbalance drilling shall only beallowed after approval by the Company Drilling Manager through the implementation of anauthorised detailed drilling programme or other written instructions.

The casing point, type of casing to be run in hole (grade, weight and coupling), types ofpreventers and their working pressure, will be selected in accordance to the predictedpressure profile, planned mud weight and required safety margins.

2.1.2. Detection OF Abnormal Well Conditions

Qualitative and quantitative methods have been developed for accurate detection of anyabnormal conditions occurring while drilling (refer to the ‘Drilling Procedures Manual’).Generally these methods are subdivided into the following groups:

• Use of previous field history and drilling experiences (depth of flowing zones, poreand fracture gradients, types of fluids, permeability, mud losses and lostcirculation intervals).

• Physical responses from the well (pit gains or losses, increases in drilling fluidreturn rates, changes in flowing temperatures, drilling breaks, variations in pumpspeeds and/or standpipe pressures, swabbing, reduction in mud densities, effectson gas shows and pit gains due to pipe connections, short and round trips, holeproblems indicating underbalance).

• Chemical and other responses from the well (chloride changes in the drilling fluid,oil and gas shows, formation water, shale density, electrical logs, drillingparameters equations and MWD/LWD readings).

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2.1.3. Kick Prevention

If primary control is lost a kick will be experienced. Common causes of kicks are:

• Swabbing in of formation fluids while tripping.• Failure to check that the hole takes or gives up the correct volume of fluid when

tripping.• Encountering abnormal formation pressure.• Having insufficient mud weight.• Loss of circulation leading to reduction in hydrostatic pressure.

It is the responsibility of the Drilling Contractor to keep the hole full at all times by using all theavailable equipment. The Drilling and Completion Supervisor shall monitor that the correctpreventive practices are being implemented and/or conducted at all times.

Extreme care shall be taken to monitor mud volume, drilling breaks and gas cut mud.

Mud Volume Control (trip volume/active volume control)

Starting with the principle that it is the ‘Drilling Contractor’s responsibility to keep the hole fullof the proper drilling fluid at all times’ through the use of monitoring devices and visualobservation, the Drilling Contractor’s crew shall continuously check the following:

• While tripping, the well takes or returns the correct amount of drilling fluidsaccording to drill pipe displacement.

• While drilling, the drilling fluids level in the circulating mud tanks alters inaccordance with the mud chemical treatment and/or penetration rate.

Quick detection of any change in the monitored well parameters, allows fast reactions to betaken aimed at a timely solution of problems, therefore:

a) While drilling:• Pit level rising, indicates that formation fluid is entering the wellbore.• Pit level falling, means that the mud pumped is being taken by the

formation. In the case of the mud level dropping in the annulus, the pressureexerted by the mud column decreases and consequently formation fluidsmay enter the borehole.

b) While tripping in and out of hole:• The piston effect occurring between the drill pipe and the hole may lead to

either surge or swab pressures acting on the formation. In both cases,variations in hydrostatic pressure may cause the well to kick, even if thecorrect mud weight is being used.

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Drilling Break

Any time a drilling break is noticed, drilling shall stop (ensure no more than 1.5m or 5ft isapplied into the break) and a static monitoring of the well shall be carried out.

• If the well is static, the Company Wellsite Drilling and Completion Supervisor willdecide whether to circulate bottoms up or resume drilling.

• If the well is flowing, the correct shut-in procedure will be implemented as quicklyas possible.

Gas Cut Mud

Gas cut mud may be a possible warning of taking a kick, so investigation of pore pressureshould be made when background gas and pipe connection gas is higher than normal.

With the presence of recurring pipe connection gas, and increasing background gas, a shorttrip should be made before pulling out of the hole, especially in over-pressured zones.

2.1.4. Maximum Allowable Annulus Surface Pressure (MAASP)

For each phase of drilling, the MAASP value depends on the following factors:

• Mud weight.• Minimum formation fracture gradient below the shoe.• Minimum casing burst resistance on the last casing string.

The MAASP shall be defined by the Company's Wellsite Drilling and Completion Supervisor,either after setting each new casing string or whenever the density of the drilling mudchanges.

The MAASP value of fracture gradient at every casing shoe depth shall be, either, stated in thedrilling programme or derived from a leak-off test.

In order to avoid casing burst or formation breakdown during well control operations, theMAASP shall be clearly written on a Kick Control sheet which will be posted near the chokecontrol panel.

2.1.5. Reduced Pump Stroke Pressure (RPSP)

The Driller is responsible for carefully measuring and recording the RPSP. The normalcirculation flowrate shall be reduced approximately to 1/3 in 121/4" and larger hole sections and1/2 in 81/2" hole sections. Awareness of these values is an important element in killingoperations, in order to avoid formation breakdown.

RPSP must be taken at the following times as a minimum:

• Once per tour, or every 300m (1,000ft) intervals.• When there is any significant changes in the mud weight or mud properties.• Whenever changes occur in the dimension and characteristics of the string, i.e.

change in BHA, jet size, jet plugged or jet lost, etc.

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On floater rigs, the RPSP shall be measured by circulating, first through the riser and thenthrough the choke/kill line. If circulating through the choke manifold, the adjustable choke mustbe completely open. On wells in deep water, at least two or more reduced circulating rates,pressures and corresponding choke line pressure losses should be recorded plus thepressure losses through both lines used in parallel.

The RPSP pressures must be measured on the choke control panel gauge or on the gaugewhich would be used during well control operations and recorded on the IADC report.

2.2. SECONDARY WELL CONTROL

The first indication of a kick may be one of the following:

• A pit gain.• A drilling break.• Increased flow across the flow line and shakers.• Gas or water cut mud returns.• A drop in pump pressure or increase in pump strokes.• Swabbing on trips (the well is not taking the right amount of mud to compensate

for pipe volume).• A total loss of circulation.

2.2.1. Kick Control Procedures (Preliminary Actions)

If there is an indication of a possible kick occurring, the Driller shall follow the kick detectionprocedures outlined below.

2.2.2. Kick Detection Procedure While Drilling

1) Stop drilling. With the pump on, pick up kelly or top drive to a predetermined position, i.e.with the tool joint clear of the preventer sealing element (and with the lower kelly cockabove the rig floor when drilling with a kelly).

2) Shut off the pumps and check for well flow by visual examination on the bell nipple orflow line.a) If the well is not flowing:

• Immediately notify the Company Wellsite Drilling and Completion Supervisor andDrilling Contractor Toolpusher.

• The Company Wellsite Drilling and Completion Supervisor will decide whether tocirculate bottoms up or resume drilling. The penetration rate will be limited as longas the cause of the abnormal situation is undetermined. Always be aware thatsome hydrocarbons (gas or oil cut mud) may rise to the surface. Ensure that theproper monitoring and safety systems all in place.

b) If the well is flowing:

• Close the well as per the ‘Shut-in Procedure’ (refer to section 3).• Immediately notify the Company Wellsite Drilling and Completion Supervisor and

Drilling Contractor Toolpusher.

2.2.3. Kick Detection Procedure While Tripping

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1) stop tripping, install a full opening safety valve (lower kelly cock).2) fill up the hole if required, and check for flow.

a) If the well is not flowing:

• If no indications of swabbing or incorrect filling have been observed resumetripping with extreme care.

• If swabbing while tripping out is observed: run back to bottom, circulate bottomsup, check for samples and consistency, increase mud weight or condition mud, ifrequired, resume tripping with extreme care, it may be necessary to pump outpipe.

b) If the well is flowing:

• Close the well as per the ‘Shut-In Procedure’.• Immediately notify the Company Wellsite Drilling and Completion Supervisor and

Drilling Contractor Toolpusher.

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3. SHUT-IN PROCEDURE.

Eni-Agip’s standard well shut-in procedure is the Soft Shut-In Procedure, unless locallegislation or third party contractor’s accepted procedures dictate otherwise and is agreedupon by the company.

The soft shut-in procedure is intended to minimise the stresses induced on casing and theformations during the first step of well control.

This procedure requires the choke line to be opened first, the bag preventer closed, and thenthe choke slowly closed.

The choke manifold and choke/kill line(s) valve positions during drilling operations shall be asfollows:

• The remotely controlled power choke on the choke manifold in a half-openposition.

• The outer choke/kill line (hydraulic) valves on the BOP in the closed position, whilethe inner valves will be open.

• The choke manifold gate valves upstream of the remote power choke and thevalves downstream of the choke to the Mud Gas Separator in the open position.

The driller must hold a record of the tool joint spacing so that a tool joint is at working heightabove the rig floor and clear of the annular sealing elements, after shut-in.

The correct distance at which kelly/top drive is to be pulled above rotary should be posted onrig floor near the BOP control panel.

3.1. SOFT SHUT IN PROCEDURE (FOR LAND RIGS, JACK UPS AND FIXEDPLATFORM)

3.1.1. Soft Shut-in Procedure While Drilling

1) Stop drilling. With the pumps on, pick up the kelly or top drive to the predeterminedposition so the tool joint is clear of the preventer sealing element (and with the lowerkelly cock above the rig floor when drilling with a kelly).

2) Shut down the pumps and check for well flow.3) Open the outer (hydraulic) valve on the choke line at the BOP stack.4) Close the annular preventer.5) Close-in the well on the remote power choke at the choke manifold. The remote power

choke is for regulating pressure only, and does not isolated pressure, therefore,immediately after the choke is closed, the gate valve upstream of the choke must beclosed to ensure that the well is effectively shut in.

6) Space out the string and close the upper pipe rams.7) Record drill pipe pressure, casing pressure and pit volume readings and calculate the

inflow volume. If a float valve is installed, the SIDPP will be derived by pressurising thedrill string until communication is established with the annulus.

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Well Shut-In

If well pressure plus RPSP exceeds 75% of the rated working pressure of the topdrive/standpipe, then use a circulation head and possibly the cement unit.

In some cases it may be considered appropriate to open the ram preventer and to keep thestring moving through the annular preventer during the control operation to prevent stuck pipe.Moving the string through the preventer may only be carried out if well control is notjeopardised.

When killing a well, first priority is to safely execute the well control operation. Potential holeproblems have a lower priority at this time and will be dealt with after the well is killed.

Use Of A Top Drive

When a top drive system is used in combination with stands, it should be possible todisconnect the string at the rotary level to be able to carry out operations which require a tooljoint near the rotary table, e.g. installation of circulating head, wireline lubricator, etc. For thispurpose a float valve or a drop in sub (preferably a retrievable type drop in valve) should beused to allow disconnection of the string below the lower IBOP of the top drive.

3.1.2. Soft Shut-in Procedure While Tripping

1) Stop tripping. Install a full opening safety valve (lower kelly cock) in the open position onthe drill string and check for well flow. If this is not possible due to the velocity of theflow, stab on the top drive if in use.

2) Set the tool joint at the correct height above the rotary table .3) Close the safety valve.4) Open the outer (hydraulic) valve on choke line at the BOP stack.5) Close the annular preventer.6) Close-in the well on the remote power choke at the choke manifold. The remote power

choke is for regulating pressure, not for isolating pressure. Therefore, immediately afterthe choke is closed the gate valve upstream of the choke must be closed to ensure thatthe well pressure is effectively closed in.

7) Space out and close the upper pipe rams.8) Connect the kelly or top drive and line up the stand pipe manifold.9) Record drill pipe pressure, casing pressure and pit volume readings and calculate


10) If the decision is made to strip back to bottom, open the pipe rams and continue as perthe ‘Stripping Procedure’ ( Refer to section 4). Otherwise start to bring the well undercontrol as per the ‘Killing Procedures’ ( Refer to section 5).

Well Shut-In

If well pressure plus RPSP exceeds 75% of the rated working pressure of the topdrive/standpipe, then use a circulation head and possibly the cement unit.

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Use Of A Top Drive

During tripping with 31/2” DP in 7” casing, the normally installed 73/8” OD lower IBOP and the73/4” - 8” OD crossover do not allow stripping operations, due to their large ODs. In this caseavoid making-up the top drive at first.

3.2. SOFT SHUT IN PROCEDURE (Floaters)

3.2.1. Soft Shut-in Procedure While Drilling

1) Stop drilling. With the pumps on, pick up the kelly or top drive to the predeterminedposition so the tool joint is clear of the preventer sealing element (and with the lowerkelly cock above the rig floor when drilling with a kelly). When picking up the drill string,the compensator will stroke fully open.

2) Shut off pumps and check for well flow.3) Open the outer fail-safe valve on the choke line at the BOP stack.4) Close-in the well on the remote power choke at the choke manifold. The remote power


5) Close the uppermost fixed size pipe rams. It is only acceptable to hang off on variablebore rams, if the tool joint will rest on ram blocks and, not on the fingers.

6) Close the ram locking device, if not automatic.7) Lower the drill pipe slowly and land tool joint on pipe rams. The lower kelly cock should

be accessible taking in account rig heave and tidal conditions.8) Move the compensator to mid stroke position and adjust to support the string weight

above the hang off rams plus a nominal overpull of 15,000-20,000lbs. (7-9t.)9) Bleed off the well pressure between annular and ram preventers via kill line. Observe

the well to verify that the rams are holding. Open the annular preventer.10) Record drill pipe pressure, casing pressure and pit volume readings and calculate


Use Of A Circulation Head

The use of a circulating head is mandatory when the drill string motion compensator is notoperational or when circulation pressures are expected to exceed the working pressure ofTop Drive/standpipe. Support the drill pipe and circulation head assembly using constanttension winches or a tensioner if necessary.

Use Of A Top Drive

When a top drive system is used in combination with stands, it should be possible todisconnect the string at rotary level to be able to carry out operation which require tool jointnear the rotary table e.g. installation of circulating head, wireline lubricator, etc. For thispurpose a float valve or a drop in sub (preferably a retrievable type drop in valve) should beused to allow disconnection of the string below the lower IBOP of the top drive.

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Deepwater Well Control Operation

Consideration must be giving to the possibility of the presence of a gas bubble above theBOP at the time of shutting-in. For this reason shut in procedure in deepwater operationsshould be modified as follows:

1) Shut-in the well as per the previous procedure above.2) Open the diverter lines and close the diverter to prevent gas entering the work area.3) If the well is flowing at the diverter line close the lower annular preventer.4) If the well is still flowing, pump fluid to the diverter to prevent riser collapse caused by

gas expansion and discharging mud from the riser.5) If the well is static at the diverter line, open the diverter and continue from step 6 of the

previous procedure above.

3.2.2. Soft Shut-in Procedure While Tripping

1) Stop tripping. Install a full opening safety valve (lower kelly cock) in open position on thedrill string and check for well flow, if this is not possible due to flow, stab on top drive if inuse.

2) Close the safety valve.3) Open the outer fail-safe valve on the choke line at the BOP stack.4) Close the upper annular preventer.5) Close-in the well on the remote power choke at the choke manifold. The remote power


6) Connect the kelly or top drive and line up the stand pipe manifold.7) Record drill pipe pressure, casing pressure and pit volume readings and calculate


8) If a decision is made to strip back to bottom continue as per the ‘Stripping Procedure’ (Refer to section 4), otherwise, hang off the drill string on the pipe rams, adjust themotion compensator and begin to bring the well under control as per the ‘KillingProcedures’ ( Refer to section 5).

Deepwater Well Control Operations

Consideration to the possibility of the presence of a gas bubble above the BOP at the time ofshutting in. For this reason shut in procedures in deepwater operation should be modified asfollows:

1) Shut-in the well as per the previous procedure above.2) Open the diverter lines and close the diverter to prevent gas entering the work area.3) If the well is flowing at the diverter line, close the lower annular preventer.4) If the well is still flowing provide liquid in the diverter to prevent collapse if gas expands

and vacates the riser.5) If the well is static at the diverter line, open the diverter and continue from step 7 of the

previous procedure above.

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3.3. POST SHUT-IN OPERATIONS

As soon as the well has been shut-in, the Drilling Contractor’s Toolpusher and the CompanyWellsite Drilling and Completion Supervisor will take all the necessary steps to ensure thewell has been properly secured and to implement subsequent well killing operations. Thefollowing inspections will be carried out:

• Inspect the BOP system components and choke manifold for leaks.• Check that all the valves on choke manifold and BOP system are in the correct

position (open or closed).• Check the BOP accumulator pressure.• Stop hot work and shut down any possible sources of ignition.• Check for overboard mud leakage and any other pollution.• Alert the stand by boat.• Confirm the ignition system on flare/burner booms are properly installed and

operational.• Check that the mud system equipment is working properly (in particular the mud

gas separator and degasser system).• Confirm breathing apparatus/masks and fire extinguishers are in correct location

and in operational condition.• Check that anti pollution equipment and dispersant is available on the rig.• Check that the emergency generator is working properly.• Calculate the inflow volume, the SICP and the SIDPP and fill in the Kill Sheet.• Confirm that the mud materials and equipment needed to circulate out the kick

are available on the rig.• Estimate the volume of extra mud in the pits.• Organise the duties of drill crew and Service Contractors for the well killing

operation.• Establish a communication system that will ensure the information flow among

the personnel involved in well killing operations is functional.• Organise a plan for possible personnel evacuation.

Prior to starting well killing operations, a meeting shall be held by the Drilling Contractor’sToolpusher and Company Wellsite Drilling and Completion Supervisor to make all personnelinvolved acquainted with operating programme and safety procedures.

3.4. PRESSURE DATA RECORDING

Drillpipe pressure and casing pressure must be monitored on the gauges on the chokecontrol panel. Low pressure gauges (which can be completely isolated when required) maybe installed on choke line and stand pipe to allow accurate measurement when low pressurekicks are taken but must always be used in deep water operations. These gauges should becalibrated regularly according to the QA schedule, and tested at regular intervals along withthe choke and kill line manifolds. At no time throughout the well control operation should thegauges in use be changed.

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4. STRIPPING PROCEDURE

4.1. OFF BOTTOM KICKS

When a kick is taken with the bit off bottom, the following factors should be considered:

• Drillpipe pressure is not a reliable indication of actual bottom hole pressure.• The position and nature of influx entered into the wellbore cannot be confirmed.

Whenever practicable, and safe the bit should be stripped back to bottom to allowimplementation of the most effective and practical killing method.

If the well is flowing, under no circumstances will the pipe be run in the hole unless stripping inis implemented.

If the well condition or any other circumstances make stripping in impossible or unsafe, thenthe bullheading, or volumetric method or off-bottom circulation may be considered.

4.1.1. Preparing To Strip-In

Assuming that a decision is made to strip-in, then the well shut-in procedure will have resultedin the installation and closure of a full opening safety valve (Lower Kelly Cock or Top DriveLower IBOP) on the drill string. Therefore, the following preparatory procedure is suggested:

a) If a float valve is installed:1) Open the safety valve and check that the float valve is holding.2) If float valve is holding, remove the safety valve.3) Proceed with stripping operations.

b) If a float valve is not installed or is leaking:1) If Top Drive is installed disconnect it above the lower BOP by using the

pipehandler.2) Install the inside BOP (Gray valve) on top of the full opening safety valve.3) Open the safety valve and ensure the Gray valve is holding.4) Leave the safety valve open and proceed with strip-in.

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The Drilling Contractor, in conjunction with the Company Representative, will prepare a planfor conducting stripping procedures. The following consideration must be taken into account:

• Organisation and supervision of the drill crew.• How to move tool joints through the BOP.• Wear on BOP elements and control unit.• Internal drill string flow control devices (i.e. utilisation of a retrievable drop-in-dart

instead of a Gray valve).• Procedure for filling the drill string.• Monitoring of pressure and fluid volumes.• Wellbore pressures in relation to the Maximum Allowable Pressure for equipment

and the formation.• Controlling increases in wellbore pressure due to surge pressure.• Control of influx migration.• Procedures to be adopted in the event that the surface pressure approaches the

Maximum Allowable Pressure as the pipe is stripped into the well.• Condition of the drillpipe (all drillpipe protectors should be removed).• Possibility of stuck pipe.

4.2. STRIPPING METHODS

Stripping-in through BOP equipment can be accomplished by using one of the following:

• The annular preventer.• A combination of annular and ram preventers.• Two ram preventers.

If the upward force generated by the well pressure acting on the cross-sectional area of thepipe is greater than the weight of the drill string, it will be necessary to force the pipe throughthe preventer by snubbing.

Stripping through the annular is the recommended method. However, the wear on the annularpacking element is related to well pressure combined with friction, due to pipe and tool jointspassing through rubber, stripping through the bag preventer should be avoided if the pressureexceeds 1,000psi (70kg/cm2).

If the surface pressure indicates that annular stripping is not possible, then considerationshould be given to reducing the surface pressure, i.e. by off bottom circulating.

If conditions require stripping using ram preventers, the lower rams shall not be used but keptin reserve.

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4.2.1. Stripping Through Annular Preventers

To prevent premature damage to the rubber element while stripping, the closing hydraulicpressure should be reduced to the minimum possible. This minimum is the point at which thebag just begins leaking a slight amount of mud. This mud leak aids lubrication of the drillpipe.

The pipe should be lowered through the annular at a speed no greater than 3min per standand reduced when the tool joints pass through the annular.

While stripping a tool joint through the preventer, the pressure regulator should automaticallyadjusted to the closing pressure, allowing the tool joint through without undue force.

If the upper annular preventer fails during stripping operations and further stripping is required,the well must be shut-in using the pipe rams and the annular repaired before continuing withoperations.

4.2.2. Stripping Through Ram Preventers

Stripping through ram preventers should only be considered when, the surface pressure isgreater than the stripping pressure of the annular preventer or if this pressure cannot bereduced to within safe annular working limits.

Bag-to-Ram stripping is preferred to Ram-to-Ram, unless surface pressures are such thatthe annular cannot operate safely.

Whichever method is used the following points must be considered:

• Is there sufficient space between the two stripping BOPs to accommodate thetool joints.

• Is there is a circulation inlet in the stack, between the two stripping BOPs, to allowfor pressure equalisation during the double opening-closure operation

• Never use the lowermost set of pipe rams for stripping.

Taking the above into consideration, Ram-to-Ram stripping is only allowed with a three piperam BOP configuration. A two pipe ram BOP configuration can only allow Bag-to-Ramstripping.

Limitations for stripping operations should be previously agreed with the contractor and BOPmanufacturer.

Stripping can be conducted using variable bore rams, but the duration of this should be limitedas the stripping capability of VBRs is poor.

The well should be secured after stripping operations and the BOP cavities inspected andrefurbished.

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4.2.3. Annulus pressure control while stripping

While stripping in the hole, it is necessary to control the well and prevent a bottom holepressure increase induced by the drill pipe volume. This is achieved by bleeding off acalculated volume of mud from the annulus. Which should be equal to the volume of pipe andtool joints, steel displacement plus the capacity of drillpipe.

Additional mud will be bleed off to compensate for influx migration. Influx migration is indicatedby a gradual increase in surface pressure even if the correct volume of mud is being bledfrom the well.

Mud should be bleed from the well at every connection. Mud bled from the annulus must beaccurately measured in order to maintain the correct volume balance and bottom holepressure.

Bleeding off should be done through a manually operated adjustable choke into the trip tankas the hydraulically operated choke has an excessive delay in operation.

When the drill string is stripped into the influx in the wellbore, the height of the influx columnwill lengthen rapidly and correspondingly the surface annular pressure will rise quicker.Whether to stop or continue stripping at this point will depend on the pressure, rate ofincrease in pressure and the distance from bottom. This has to be evaluated on site andcorrect/remedial actions taken.

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4.2.4. Stripping Worksheet

STRIPPING WORK SHEET

Well N° 3 Rig 15 Date and Time 10/05/85 Sheet N° 1MUD WEIGHT IN THE HOLE 1.75 SG LUBRICATING MUD WEIGHT 1.75 SGINITIAL BIT DEPTH 2000 m HOLE DEPTH 2250 mSTRIPPING DATAVOLUME OF MUD DISPLACED BY 5 in DRILLPIPE: 0.0797 bbl/m : 2.15 bbl/standOVERBALANCE MARGIN: 120 psi OPERATING MARGIN: 150 psi (Max)VOLUMETRIC CONTROL DATAHYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 5" x 8 1/2" ANNULUS: 16.5 psi/bblHYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 6 1/2 x 8 1/2 ANNULUS: 26 psi/bblHYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 8 1/2" HOLE: 10.8 psi/bblHYDROSTATIC PRESSURE PER BARREL OF MUD IN HOLE: psi/bbl

Timehr.min

Operations CHOKEMonitorPressure

(psi)

Change inMonitorPressure

(psi)

BIT Depth(m)

Pipe Stripped

(m) (bbl)

Hydrostatic ofMud Bled/lubricated

(psi)

Over-balance

(psi)

Volume ofMud/

Lubricated(bbl)

TotalVolume ofMud (bbl)

10:05 Well shut in- pressure stabilised 550 2000

10:20 Drill pipe dart installed 2000

10:30 Strip in stand N° 1 770 + 120 2027 27 2.2 N/A + 120 0 0

10:36 Strip in stand N° 2 890 + 120 2054 54 4.4 N/A + 240 0 0

10:40 Bleed mud at connection 770 - 120 2054 54 4.4 N/A + 120 +2.2 2.2

10:45 Strip in stand N° 3 890 + 120 2081 81 6.6 N/A +240 0 2.2

10:48 Bleed mud at connection 770 - 120 2081 81 6.6 N/A + 120 + 2.2 4.4

10:53 Strip in stand N° 4 890 + 120 2108 108 8.8 N/A + 240 0 4.4


11:00 Strip in stand N° 5 (assume BHA hasentered influx)

950 + 180 2135 135 11.0 N/A + 240 0 6.6










+ vlincrease- vldecrease

m/ft m/ft - vl bled+vl lubricatedN/A bled tocompensate forpipe

+ vloverbalance- vlunderbalance

+ vl bled-vllubricated

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5. KILLING PROCEDURES

5.1. WELL CONTROL METHODS

All methods to be used to bring the well under control are based on the ‘Constant Bottom HolePressure’ concept, as recommended by API-RP 59 ‘Recommended Practices for WellControl Operations’.

This methods requires a constant bottom hole pressure, slightly higher than the porepressure, to be maintained at all times throughout the killing operations in order to preventfurther influxes occurring.

The mud weight necessary to achieve control of the well, shall be calculated as a function ofthe Shut-In Drill Pipe Pressure, hole depth (TVD) and actual mud weight.

Other permitted well control methods, depending on particular situations, are the ‘Wait andWeight’, ‘Driller’s Method’ and the ‘Volumetric Method’.

Bullheading may also be considered when the other preferred killing methods are notapplicable. Bullheading is often an operationally acceptable permitted method in killingproducing wells, e.g. actual production wells or production well tests in cased wells.

In an order of preference, the Wait and Weight method is first, but if this is not a practical,then the Driller’s Method will be used followed finally by the Volumetric Method.

Once the method for dealing with the kick has been selected by the Company Representative(Wellsite Drilling & Completion Supervisor and/or Drilling Superintendent), the DrillingContractor’s personnel should perform the operation following the selected method and usingthe proper practices.

The Drilling Contractor's personnel must be familiar with the Kick Control worksheets(Company, Contractor’s approved, or API forms) in use and with the relevant calculationsinvolved. They must be also be able to fully understand and implement the results of thesecalculations. Eni-Agip’s kill sheets are shown in figure 5.a and figure 5.b.

5.1.1. Wait And Weight Method

The well is shut-in until the mud (kill mud) can be weighted up in the pits to the requireddensity or the reserve heavy mud can be conditioned to the required density. The kill mud isthen circulated into the well displacing the kick. Bottom hole pressure shall be kept slightlygreater than pore pressure throughout the entire process, while the pump rate is maintainedat the predetermined rate.

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Wait And Weight Killing Procedure

1) Before starting with the killing operation it is necessary to determine the InitialCirculating Pressure (ICP) and the Final Circulating Pressure (FCP) of the kill mudbeing pumped down hole. A schedule (plot and table) must be prepared in order that thedrillpipe pressure can be properly tracked through choke position. The plotted lineshould be a straight line except when there is tapered strings and deviated wells.

2) It is important that the volume of the kill mud, position of the influx and drill stringgeometry are known at all times throughout the kill operations. The key control points inthis process are: the kill mud reaching the bit; the top of the influx reaching the casingshoe and the influx reaching the choke on surface.

3) The choke will be opened following the pump start up, ensuring that the casing pressureis kept equal (or slightly in excess) of the original SICP.

4) The pump should be brought up to the RPSP speed slowly. Once RPSP is reached,the choke should be adjusted until the standpipe gauge reads the calculated ICP.

5) If the ICP is close to the calculated value, continue with the displacement operation. If itis substantially different, investigate the cause and recalculate the FCP.

6) The pump (drill pipe) pressure shall be adjusted (reduced), using the power choke inaccordance with the kill sheet graph and table, accounting for the volume of the heavierkill mud filling the drill string. Pump pressure should not be allowed to drop below thecalculated values.

7) Once kill mud reaches the bit, the drill pipe pressure should equal the calculated FCP.From now on, the FCP value shall be kept constant until the influx is completelycirculated out.

8) It is important, therefore, that the choke is continuously adjusted to maintain the requireddrillpipe pressure. This is especially important from the time the influx reaches thechoke until neat kill mud is observed.

9) During displacement the pit gain will be recorded so that the position of the influx in thewell can be estimated.

10) After circulation is completed (i.e. when kill mud entirely fills the well and circulatingsystem) the pump can be shut down and the well shut-in for pressure monitoring. Thecasing and drillpipe pressure will both be checked. There should be no pressure oneither of the gauges. If, however, there is still some pressure, through-choke circulationwill be resumed until the contaminated mud is removed from the annulus.

11) Once the well has been killed, a flow check will be carried out prior to opening the BOP.12) Drilling crews must be aware that there may be gas trapped under the BOP rams,

hence safety procedures should be implemented prior to opening the BOP.13) Prior to resuming drilling operations a full circulation will be carried out, with the mud

being weighed up to a suitable overbalance.

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5.1.2. Driller’s Method

Two separate circulations are required with this method to kill a well.

In the first circulation the influx is circulated out, at a constant pump rate, using the same muddensity that is in the hole at the time of the kick. The Initial Drill Pipe Pressure must be heldconstant, by choke manipulation, to ensure the bottom hole pressure remains constant. Afterthe influx has been circulated out at the end of the first circulation, the Shut-In Drill Pipe andCasing Pressure should be equal, and equal to the initial shut-in drill pipe pressure.

The choke pressure during this circulation will be higher than those if the ‘Wait and Weightmethod’ was used. This leads to greater downhole, stress and pressures.

During the second stage circulation, the well is brought under control by circulating therequired kill mud into the hole in the same manner as described in the ‘Wait and Weightmethod’.

Driller’s Killing Procedure

First stage

Circulating out the influx from the well and maintaining constant bottom hole pressure:

1) Open the choke following pump start up, ensuring that the casing pressure is kept equal(or slightly in excess) of the original SICP. The pump should be brought up to speedslowly.

2) Once the pump has reached the required RPSP speed, record the Initial CirculatingPressure. If the ICP is close to the calculated value, continue circulating, holdingconstant pump speed and drill pipe pressure.

3) Continue circulating, maintaining the Drillpipe Circulation Pressure and pump strokeconstant, until the influx is completely circulated out.

4) The choke will be continuously adjusted to maintain constant drillpipe pressure. This isespecially important when the influx reaches the choke, and then when the mudreaches the choke.

5) The pit gain during displacement should be recorded so that position of the influx in thewell can be estimated.

6) After the influx has been displaced from the well, the Shut-In Drillpipe Pressure and theShut-In Casing Pressure should read the same. If the casing pressure is higher thanthe drillpipe pressure then some of the influx will still be in the annulus, or there will besome differential mud pressure inside and outside the drill string.

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Second Stage

Displacing the well with kill mud keeping Bottom Hole Pressure constant.

1) Once the kill mud has been prepared, the second phase can begin.2) It is important that the volume of the kill mud and its position, in relation to the wellbore

and drill string geometry, are known at all times during kill operations.3) Open the choke following the pump start up, ensuring that the casing pressure is kept

constant (or slightly in excess) of the value recorded at the end of first circulation. Thepump should be brought up to the RPSP speed slowly.

4) Displace the mud in the drill string with the kill mud, keeping both the casing pressureand pump strokes constant, until the kill mud reaches the bit. As the kill mud isdisplaced down the drillpipe, the stand pipe pressure will tend to decrease accordingly.

5) Once the displacement of the mud in the string is completed, the Final CirculationPressure (FCP) can be read on the drillpipe gauge. This pressure and the pump speedmust be kept constant throughout the displacement of the mud in the annulus, until thekill mud reaches surface.

6) After the circulation is completed i.e. when kill mud entirely fills the well and circulatingsystem, the pump can be shut down, and the well shut-in for pressure monitoring. Boththe casing and drillpipe pressures should be checked. There should be no pressure oneither gauge. If, however, there is still some pressure, through-choke circulation will beresumed until unbalanced or contaminated mud is removed from the well.

7) Once the well has been killed, a flow check will be carried out prior to opening the BOP.8) The Drilling crews must be aware that there may be gas trapped under the BOP rams,

hence safety procedures should be implemented prior to opening the BOP.9) Prior to resuming Drilling operations a full circulation will be carried out, with the mud

being weighted up to a suitable overbalance.

5.1.3. Volumetric Method

The volumetric method can be used to control the gas expansion, migrating up-hole, duringthe shut-in period. This only occurs when the influx is gas.

Situations in which the volumetric method may be applicable include the following:

• When the mud pumps are inoperable• The drill string is far off the bottom, or out of the hole• There is a washout in the drill string• The bit is plugged• The drill string has parted and dropped.

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Volumetric Killing Procedure

In this method the bottom hole pressure is maintained relatively constant and slightly inexcess of the pore pressure whilst the gas is allowed to expand as it migrates up to thesurface.

1) A constant bottom hole pressure is maintained by bleeding off mud, with an equivalenthydrostatic head, equal to the rise in pressure caused by migrating gas. For instance ifthe choke pressure rises by 100psi, a volume of mud equivalent to the hydrostaticpressure of 100psi is slowly bled off, maintaining constant casing pressure.

2) Bleed off in very small increments to allow the pressure to respond by using a manualadjustable choke and diverting the mud into the trip tank.

3) Repeat this process until the influx has migrated up to the BOP.4) When the gas is at the BOP stack, lubricate mud into the well. The lubrication

procedure will replace the influx with mud, as the gas is bleed off at the choke.5) Pump mud into the casing until pump pressure reaches the predetermined limit and

stop the pump.6) Leave the well shut-in for a time to allow gas to migrate through the lubricated mud.7) Bleed gas from the well until the surface pressure is reduced by the exact amount equal

to the hydrostatic pressure of the fluid volume lubricated into the well.8) Route returns via the mud gas separator and monitor. If a significant quantity of mud is

returned, bleeding should be stopped, and further time allowed for the gas to migratethrough the lubricated mud.

9) It is unlikely that all the gas will rise to surface as a discrete bubble and it will be mixedthrough the mud, therefore, will take a considerable length of time to be completed.

10) When using subsea BOP stacks, gas migration may occur in the choke line leading toa reduction in bottom hole pressure. In this case, a dynamic volumetric method is usedfor venting the gas from the subsea BOP, by circulating down the kill line and up thechoke line. Control surface pressure and pit gain with the choke line. Use the kill line beused to monitor bottom hole pressure.

Note: If the mud weight is insufficient to balance the formation pressure, it willbe necessary to strip drill pipe into the well to implement a standard wellkill method.

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5.1.4. Volumetric control worksheet

VOLUMETRIC CONTROL WORK SHEET

Well N° 10 Rig 2 Date and Time 12/12/96 Sheet N° 1MUD WEIGHT IN THE HOLE 1.85 SG LUBRICATING MUD WEIGHTHYDROSTATIC PRESSURE PER BARREL OF 1.85 SG MUD IN 5" x 8 1/2" ANNULUS: 17.5 psi/bblHYDROSTATIC PRESSURE PER BARREL OF MUD IN x ANNULUS: psi/bblHYDROSTATIC PRESSURE PER BARREL OF MUD IN HOLE: psi/bblHYDROSTATIC PRESSURE PER BARREL OF MUD IN HOLE: psi/bblOVERBALANCE MARGIN: 200 psi OPERATING MARGIN: 150 psi

Timehr.min

Operations CHOKEMonitor

Pressure(psi)

Change inMonitor

Pressure(psi)

Hydrostaticof Mud Bled/

lubricated(psi)

Overbalance(psi)

Volume ofMud/

Lubricated(bbl)

TotalVolumeof Mud

(bbl)

19.00 650 0 0 0 0 100

19.15 INFLUX MIGRATING 850 + 200 0 + 200 0 100


19.25Ù 01.25 BLEED MUD AT CHOKE 1000 0 - 150 + 200 + 8.5 108.5

01.35 INFLUX MIGRATING 1150 + 150 0 + 350 0 108.5

01.35Ù03.15 BLEED MUD AT CHOKE 1150 0 - 150 + 200 + 8.5 117


03.30Ù04.45 BLEED MUD AT CHOKE 1300 0 - 150 + 200 + 8.5 125.5

04.55 INFLUX MIGRATING 1450 + 150 0 + 350 0 125.5

04.55Ù05.30 BLEED MUD AT CHOKE 1450 0 - 150 + 200 + 8.5 134

+ vl increase- vl decrease

- vl bled+ vl lubricated

+ vl overbalance- vlunderbalance

+ vl bled-vl lubricated

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5.1.5. Bullheading

The bullheading method should only be considered when normal killing techniques withconventional circulation are not possible or will result in causing critical well conditions.

Bullheading is usually only considered when the following situations occur:

• A H2S influx cannot be handled safely by rig personnel and equipment.• A kick is taken with the pipe far off bottom, or even out of the hole.• Circulating the kick out may result in excessive gas rates at surface.• Kick calculations show that the MAASP will be greatly exceeded during

conventional kill operations.• Killing completed wells, i.e. actual producing wells or production well tests in

cased wells.

Major factors that will be considered to determine the feasibility of bullheading are as follows:

• Characteristics of the open hole formations, including fracture gradients andestimated permeability.

• Rated pressures of casing, making allowance for wear and deterioration.• Size, location and nature of the influx.• Consequences of fracturing a section of open hole.

Bullheading should be performed with an aim of not fracturing the formation. The surfacesqueeze pressure applied should not exceed the precalculated MAASP.

Bullheading procedures will be defined and decided at the rigsite, in response to the particularcircumstances which prevail, taking into considering that the mud and influx are squeezedback downhole into the weakest exposed open hole formation. If the influx is suspected ofcontaining H2S, it may be acceptable to squeeze it away downhole provided that casingprofile and nature of the formation overlaying the weakest strata, ensures proper isolation. Inother circumstances, e.g. where surface permeable formations are exposed or only a surfacecasing is set not ensuring proper strata isolation, this practice is prohibited.

5.2. HORIZONTAL WELL CONSIDERATIONS

The previous described Well Control Procedures should apply at all times, however, the drillcrew must take into consideration some particular aspects related to the drilling of horizontalwells:

a) When a long section of reservoir is exposed, there is the potential for large andrapid kicks.

b) Large sizes of influx can exist in the horizontal section with a minimum effect onbottom hole pressure.

c) Assuming that the fluid parameters and pressure are known, the most likelycause of a kick is due to swabbing, losses, or crossing a fault.

d) Where swabbing of fluid in the horizontal section, both the shut in drill pipepressure and shut in casing pressure will be zero until the influx reaches thevertical section.

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a) The practice of hole cleaning minimises cutting beds, which can increase thelikelihood of swabbing. Always pump out the pipe when tripping in the horizontalsection as this will enhance hole cleaning and reduce the possibility of swabbing.

b) Volumetric increases are the most reliable indication of a kick as pit levels andflow rate changes will be the same as in a vertical section. Flow checks whiletripping-out do not provide a reliable indication that an influx has not alreadyentered in the horizontal section as migration may not occur in the horizontalsection.

c) If a kick occurs, due to a fault or insufficient mud weight, it is unlikely that there isany difference between the Shut In Drillpipe and Shut In Casing Pressure whenthe influx is in the horizontal section.

d) Until the influx is circulated out of the horizontal section there is no increase in thecasing pressure.

e) When killing the well using the 'Wait and Weight' method, the final circulatingpressure should be reached when the kill mud reaches at the start of thehorizontal section not at the bit.

f) The unevenness of the horizontal sections may also trap pockets of gas on thehigh side and this may require more than one circulation to be removed.

5.3. FLOATING RIG CONSIDERATIONS

5.3.1. Effect Of Choke Line Length

When a kick is taken on a floating rig, the influx will be brought to surface via the relativelysmall diameter choke line. This introduces major problems that are not present when BOPsare at surface, as on fixed rigs.

a) The pressure losses generated in the choke line while circulating are consideredand may cause excessive pressures in the wellbore. These pressure losses canbe reduced by reducing the circulating rate. If the circulation rate is reduced, it isnecessary to have predetermined RPSP for that reduced rate. At least two ormore RPSPs should be taken.

b) As an influx enters the choke line, it may cause a critical drop in bottom holepressure. To avoid this, as a gaseous influx is nearing the seabed, the mudcirculation rate should be reduced to the minimum in order to allow, the variationsof gas height in the choke line to be monitored following each choke adjustment,and so maintain constant bottom hole pressure.

c) For deep water operations it is necessary to record the pressure losses in thechoke, kill and combination of choke and kill lines. During a well control operation,consideration should always be given to opening both the choke and kill lines tothe choke manifold. By increasing the flow area, the reaction time will beincreased, making it easier to maintain constant bottom hole pressure. In addition,by increasing the choke line volume, the surface pressure will be lower, thusreducing gas velocity, erosional wear and the possibility of a surface systemfailure.

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5.3.2. Influx Removal From BOP And Riser

It is possible that gas may have accumulated between the closed BOP and the choke linewhen used for killing operations. Before opening the subsea BOP, it is necessary to circulatethrough the choke or kill line in an attempt to remove this trapped gas.

Before opening the well, the light mud in the marine riser must also be displaced by kill weightmud.

The suggested procedure is:

1) Isolate the well from the BOP stack by closing the lowermost set of pipe rams, keepingthe annular preventer/ram closed.

2) Pump mud through the upper kill line and discharge the tapped gas up the lower kill line.3) Close the diverter.4) Open the annular BOP and pump kill mud through the choke and kill line, replacing the

light mud in the riser with kill weight mud.

Note: If the rig is fitted up with a ‘booster line’, the mud in the riser can bechanged out by using it before opening the BOP.

When the riser is filled with kill mud, redirect the pump feed to thestandpipe manifold, open the rams and carry out a further flow check.

ARPO




Figure 5.A - Well Data Work Sheet

Leack-off test pressure Hydrostatic pressure of Mud to Shoe

Vertical shoe depth Fracture gradient Max. equivalent muddensity

Kg/cm² Kg/cm² m Kg/cm²/10 m Kg/ lx 10 =/+

MEMW

Max. equivalent muddensity

Actual mud density Shoe vertical depth MAASP

Kg/ l Kg/ l m Kg/ cm² 10 x/-MAASP

CASING BURSTNEW CASING burstresistence

Securety factor

Kg/cm² =xAllowable burst pressure

Kg/cm²

B.H.A.O.D in.

I.D in.

Weight lb/ft

D.P.

H.W.D.P

D.C.

D.C.

Capacity l / m

Length m

Volume l

Tot Tot

AnnulusCapacity l / m

D.P x CSG.

D.P X HOLE

H.W.D.P. X HOLE

D.C.x HOLE

D.C.x HOLE

Length m

Volume l

Tot Tot

S.P.M.

Type................

Liner sizein.............................Pumps

Slow Circulate PressurePump Nr 1 Kg/cm²

Pump Nr 2 Kg/cm²

Press. loss to chokeChoke Nr 1 Kg/cm²

Reduced Pump StrokePump Nr 1 Kg/cm²

Pump flow rate

l/stk eff. l/stk Kg/cm²x =RPSP

Choke lineKill lineRiser

O.D. in.

Capacity l/m

I.D. in.

Length m

Volume l

1

2

3

4

5

WELL DATA WORK SHEET

Rig name............................................

Well name..........................................

Company man....................................

Date....................................................

Casing O.D. in Wt. lb/ft

Shoe depht

Misured

Verticalm

mBit to Shoe volume l

R.K.B. - Sea Bed

m

l/m

l/m

l/m

l/m

m

m

l/m

Bit diameterBit depht

M.D.

T.V.D.

l/m

3

4

5

2

1

Choke Nr 2 Kg/cm²

Pump Nr 1 Kg/cm²

=

=

Pressure

Eni-Agip

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Figure 5.B - Kill Sheet

Kg/cm²

KICK DATA

SIDPP Bit vertical depht Original Mud Weight Kill Mud Weight

Kg/ cm² m Kg/l Kg/lx 10 +:

KILL MUD WEIGHT

PRESSURE RECORDING

KILL SHEET

Date....................................................

Well

Company

Time of

Kg/cm² l Kg/l m

SIDPP SICP Pit Gain Gom T.V.D

Kg/cm²

MAASP

=

P.T.R.Fondo mareSIDPP SICPTime SIDPP/TIME SICP//TIME

INITIAL CIRCULATING PRESSURE PUMP STROKES

l l/stk s tk

+ + =SIDPP RPSP Safety margin ICP

Kill mud Weight

Original mud Weight

Kg/ cm² Kg/ cm² Kg/ cm²=+x

RPSP Safety margin FCP

Drill string volume Surface to BitPump Output

l l/stk s tk

l l/stk s tk

Bit to shoe volume

Total annulus volume

Bit to shoe

Bit to surface

=

=

=

:

:

:

DRILL PIPE PRESSURE GRAPH

Pressure

Pump strokesDRILL PIPE PRESSURE CHART

Kg/cm²

Pump STKS

psi

FINAL CIRCULATING PRESSURE

Kg/ cm² Kg/ cm² Kg/ cm²Kg/ cm²

SIDPP SICPTime SIDPP/TIME SICP//TIME

Pump Output

Pump Output

Eni-Agip

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6. EQUIPMENT REQUIREMENTS

6.1. BOP STACK SYSTEMS

6.1.1. Land Rigs, Jack-Ups And Fixed Platform

a) The pressure rating requirement for BOP equipment is based on the ‘maximumanticipated surface pressure’ as stated in the Drilling Procedures Manual’. Projects thatrequire a different working pressure in the whole system shall be agreed upon by theCompany and Drilling Contractor.The minimum BOP stack requirements are as follows:

A 5,000psi WP stack should have at least:

• Two ram type preventers (one shear ram and one pipe ram).• One 2,000psi annular type preventer.

A 10,000psi stack should have at least:

• Three ram type preventers (one shear ram and two pipe ram).• One 5,000psi annular type preventer.

A 15,000psi stack should have at least:

• Four ram type preventers (one shear ram and three pipe ram)• One 10,000psi annular type preventer.

b) While drilling, all pipe ram preventers shall always be equipped with the correct sizedrams to match drill pipe being used. If a tapered drill string is being used e.g. 31/2” and5”, one set of rams will be dressed to match the smaller drill pipe size.During casing jobs or production testing, the choice of pipe rams shall be defined by theCompany, depending on external diameter(s) of the casing/drilling/testing string(s) inthe operation and BOP stack composition.

c) At least one ram preventer, below the shear rams, shall be equipped with fixed piperams to fit the upper drill pipe in use. The minimum distance between shear rams andhang-off pipe rams shall be 80cm (30”).

d) The use of variable bore rams (VBRs) is acceptable but they should not be used forhanging off pipe which is near to the lower end of their operating range.

e) Rig site repair of BOP equipment is limited to replacing of worn or damaged parts.Under no circumstances is welding or cutting to be performed on any BOPequipment. Replacement parts should only be those supplied or recommended by theequipment manufacturer.

f) Each choke and kill line BOP outlet shall be equipped with two full bore valves, the outervalve of which will be hydraulically operated (preferably fail-safe closed).

g) The minimum diameter of the choke line will be 3" ID, while the kill line should have notless than a 2" ID. Articulated choke lines (Chiksan) are not acceptable unlessderogation is agreed for a particular application.

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a) A number of various arrangements in the position of the choke and kill line outlets areused in BOP stack configurations throughout the oil industry. The rig operating manualshould highlight these variations, their limitations and all the potential uses of a particularlayout.

b) The inclusion of shear rams requires the choke and kill lines positions to be such thatthe direct circulation of the kick, through the drill pipe stub after shear rams activation,can be performed with the drill string hang-off on the closed pipe rams and holdingpressure.

c) On a four ram BOP stack, Eni-AGIP recommends that the positioning of choke and killline outlets below the lowest pipe rams be avoided as these are the like the last resort‘Master Valve’ of the BOP stack.

6.1.2. Floating Rigs

a) The minimum BOP stack requirements for floating rigs are as follows:A 10,000 psi stack should have at least:

• Four ram type preventers (one shear ram and three pipe rams)• One or preferably two 5,000psi annular type preventers (one annular

retrievable on Lower Marine Riser Package).

A 15,000 psi stack should have at least:

• Four ram type preventers (one shear ram and three pipe rams)• Two 10,000psi annular type preventers (one annular retrievable on the

Lower Marine Riser Package).

b) The upper hydraulic connector shall have a pressure rating equal to or exceeding theworking pressure of the bag type preventers.

c) The BOP stack will contain pipe rams that are able to close on every size of drillpipe/tubing that will be run through the stack.The use of VBRs is acceptable but they should not be used for hanging off pipe which isnear to the lower end of their operating range.

d) At least one ram preventer below the shear rams shall be equipped with fixed pipe ramsto fit the upper drill pipe in use. The minimum distance between shear rams and hang-off pipe rams shall be 80cm (30”).

e) Each choke and kill line BOP outlet shall be equipped with two fail-safe, remotelycontrolled gate valves, rated to the BOP working pressure. The valves shall be fail-safein the closed position.

f) The minimum diameter of choke/kill lines will be 3" ID. The function of each line must beinterchangeable at surface to be able to line up with both the rig pumps and the chokemanifold.

g) A number of various arrangements in the position of choke/kill line outlets are used inBOP stack configurations throughout the oil industry, The rig operating manual shouldhighlight these variations, their limitation and all the potential uses of the particularlayout.

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a) The inclusion of shear rams requires choke and kill line positioning such that the directcirculation of the kick, through the drillpipe stub after shear rams activation, can beperformed with the drill sting hang-off on closed pipe rams holding pressure.

b) Eni-Agip recommends that choke and kill line outlets are positioned above the lowestpipe rams as these are the like the last resort ‘Master Valve’ of the BOP stack.

c) For deep water operation, it is recommended to use a BOP stack equipped with aninjection line to pump methanol or glycol, in order to reduce the likelihood of hydratesforming during well control operations. It is also recommended that pressure andtemperature gauges are located on the BOP stack.

6.2. BOP CONTROL SYSTEM

6.2.1. Land Rigs, Jack-Ups And Fixed Platform

a) The accumulator system should be capable of closing each ram BOP within 30 secs.The closing time should not exceed 30sec for annular preventers smaller than 183/4”nominal bore and 45sec for annular preventers of 183/4” and larger.

b) Hydraulic operating equipment shall have at least a 3,000psi accumulator unit equippedwith two regulator valves, one to reduce the operating fluid pressure to 1,500psi and theother for further reduction of pressure for bag type preventer operations.

c) The capacity of the accumulators should be, at least, equal to the volume (V1),necessary to close and open all BOP functions installed on stack once, plus 25% of V1.The liquid reserve remaining on accumulators should still be the minimum operatingpressure of 1,200psi (200psi above the precharge pressure).

d) The control panel shall be fitted with visual and acoustic alarms for signalling of lowaccumulator pressure, as well as control fluid reservoir low level.

e) A minimum of two air-driven pumps and one electrically driven triplex pump is requiredfor charging the accumulators. The combination of air and electric pumps shall becapable of charging the entire accumulator system from the precharge to full chargepressure within 15min or less.

f) In addition to the hydraulic master control panel, the BOP control system shall includeat least one graphic remote control panel located on the rig floor near the Driller’sconsole. Offshore units shall have an additional graphic remote control panel located ata safe distance from the rig floor usually in toolpusher’s office or adjacent to the escaperoute from drilling unit. Each remote control panel shall be connected to the controlmanifold in such a way that all functions can be operated independently from eachpanel.

g) A safety device shall be installed on the BOP control manifold and remote panels toprevent accidental operations of BOP controls such as the closure of the rams (pipe orshear) on the drilling string while drilling or tripping.

h) The BOP end of the control hoses must be flexible and fire proofed.i) The BOP accumulator electric-driven pump shall be connected to an emergency

source of power.

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6.2.2. Floating Rigs

a) The accumulator system should be capable of closing each ram BOP within 45sec andeach bag type preventer in less than 60sec.

b) Two complete independent control systems (yellow pod and blue pod) are required toensure redundant control of all stack functions.

c) The rig should be equipped preferably with an emergency and fully independentacoustic control system. This system shall be used when the rig is off location or in theevent of a main control system failure. The associated subsea accumulator shall bemounted on the BOP stack, not attached to the LMRP and should have a capacityadequate for closure: one ram type preventer, shear rams, and for releasing the LMRPconnector.

d) Hydraulic operating equipment shall have at least a 3,000psi accumulator unit completewith a soluble oil/water reservoir and equipped with two regulator valves, one to reducethe operating fluid pressure to 1,500 psi and the other one for further reduction ofpressure for bag type preventer operations.

e) Accumulator capacity should be, at least, equal to the volume necessary to close, openand close (with charging pumps inactive) all ram type preventers and one bag typepreventer with a resulting system pressure of 200psi above the precharge pressure.The fluid volume needed to meet this requirement is the theoretical volume to close,open and close the preventers increased by a 25% factor to compensate for fluid lost tofunction the SPM valves. When a portion of accumulator volume is located on the BOPstack, the additional precharge pressure required to offset the hydrostatic head of theseawater should be considered.

f) The control panel shall be fitted with visual and acoustic alarms for low signallingaccumulator pressure, as well as control fluid reservoir low level.

g) A minimum of two air-driven pumps and one electrically driven triplex pump is requiredfor charging the accumulators. The combination of air and electric pumps shall becapable of charging the entire accumulator system from the precharge to full chargepressure in 15min or less.

h) In addition to the hydraulic master control panel, the BOP control system shall includeat least two graphic remote control panels. One panel shall be located on the rig floornear the Driller’s console, the other panel shall be located at a safe distance from the rigfloor usually in toolpusher’s office or adjacent to the escape route from drilling unit. Eachremote control panel shall be connected to the control manifold in such a way that allfunctions can be operated independently from each panel.

i) A safety device shall be installed on the BOP control manifold and remote panels toprevent accidental operations of BOP controls such as the closure of the rams (pipe orshear) on the drilling string while drilling or tripping.

j) The BOP accumulator electric-driven pump shall be connected on the emergencysource of power.

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6.3. CHOKE MANIFOLD

a) All choke, kill lines and choke manifold components which may be exposed to wellpressure shall have a working pressure rating equal to or greater than that of thepreventers in use.

b) The minimum recommended size for all choke lines and valves is 3” (76.2mm). Allvalves shall be of full-opening gate valve types.

c) Choke manifold shall be equipped with at least four flow lines.• One line shall be capable of bringing the well return directly to the buffer manifold

and shall be equipped with two gate valves.• At least three lines shall be equipped with adjustable chokes, two gate valves

upstream and an erosion nipple immediately downstream. At least one chokeshall be remote hydraulically operated.

d) A graphic scheme of the choke manifold shall be posted on the rig floor.e) The buffer shall be capable of diverting well returns to the mud gas separator, the shale

shaker, the burner booms or the flare line.f) A choke manifold of different design from that already installed on the drilling unit, may

be acceptable but only if approved by the Company Drilling Manager.

6.4. INSIDE PIPE SHUT-OFF DEVICES

a) The Kelly or Top Drive, shall be equipped with an upper and a lower kelly cock infunctioning condition. The kelly cock’s WP shall be equal to or greater than the rating ofthe preventer stack in use. The upper kelly cock of the top drive shall be hydraulicallyoperated.

b) A spare full opening safety valve (lower kelly cock) that is compatible with drill pipe inuse shall be stationed on the rig floor at all times, in the open position and complete withremovable handles for ease stabbing.

c) Crossover for connecting the full opening safety valve to the drill collars or tubing in useshall be also stationed on the rig floor.

d) A Gray type inside BOP, with the appropriate connections for the drill string in use, shallbe stationed on the rig floor at all times.

e) One drop-in type back pressure valve, complete with seating subs to fit the drill string inuse, shall be available. The wireline retrievable is the preferred type.

f) Any type of string tools installed above this sub shall have an ID greater than drop-invalve OD.

g) A set of float valves, one for each size of drill collar, and one for drill pipes in use, shallbe kept available.

ARPO




6.5. MUD GAS SEPARATOR

a) A suitable atmospheric mud gas separator, arranged with the inlet line from chokemanifold and the outlet line (discharging released gas) connected to a flare return, mustbe provided.

b) The mud gas separator design shall be based on the liquid seal system matched to oneor more gas outlets (vent lines) leading a safe distance downwind from the well and/orto the top of the derrick. The liquid seal ensures that separated gas vents safely withoutbreaking through to the mud tanks. The mud seal may be obtained by means of anexternal U-tube or may be based on a dip tube extending into the trip tank.

c) The mud seal should be at least 10ft (3m.) high.d) Vent line should not be less than 6” nominal pipe diameter. For vent lines exceeding the

length of 130ft (40m.), the diameter of the vent line should be not less than 8” to ensurethat the back pressure in the vent line does not exceed the hydrostatic mud seal.

6.6. DIVERTER EQUIPMENT

a) Whenever possible, there must be at least two discharge lines always ending laterally inopposite points of the rig to enable the possibility of blowing to the leeward side.

b) Diverter outlets and lines shall have a minimum internal diameter of 12” for offshore rigsand 10” for land rigs. Welded flanges or clamped connections are mandatory.

c) Diverter lines shall maintain a uniform diameter throughout, and should be as straightas possible to reduce erosion and back pressure (90° or greater bends are to beavoided). Diverter lines should be securely anchored, especially at bends and at the endof the lines.

d) Diverter valves shall be full opening valves, preferably ball valves, and pneumatically orhydraulically actuated. The use of butterfly valves is forbidden.

e) The automated system shall be set, to allow for the immediately automatic opening ofthe discharge lines, followed by closure of the shale shaker line and before closing thediverter packing.

f) In the panel, bright indicators must show the working pressure of the accumulators andthe actual pressure of the various functions. A regulator must permit changes from, theminimum to the maximum closing pressure of the diverter seal.

g) Each diverter system should incorporate a kill line (including a valve) to be able to pumpwater through the diverter system. Pumping water or mud through this line is importantto reduce the risk of explosion or fire during a blow out. This line is also needed to fill upthe hole, at all times, so that it can be kept full in the event of losses to the formation.

h) It should be possible to control pumping operations at the pumps as well as on the drillfloor.

i) The control system of diverter should be capable of closing any diverter smaller than20” within 30sec, and any diverter/annular of 20” or larger within 45sec. Diverter valvesshould be opened before the diverter element is completely closed.

j) The diverter control system should be capable of operating the diverter system fromtwo locations, one to be situated near the drillers position. All control functions must beclearly labelled for identification.

k) When both the diverter system and BOP stack are employed as on floating rigs,control/accumulator systems of diverter and BOP stack shall be separate units and fullyindependent.

l) The control panel of the diverter assembly must be able to operate the diverter packing,

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the discharge valves, the shale shaker valve (if installed) both simultaneously and/orseparately.

m) The telescopic joint should incorporate double seals to improve sealing capability.

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6.7. AUXILIARY EQUIPMENT

a) The trip tank system shall include centrifuge pumps, fill up the line, recirculating circuitand a mechanical mud level device equipped with reading indicator easily visible to theDriller. The minimum capacity of the trip tank should be 5m3 (30bbls).

b) A mud pit level volume indicator shall be installed on each tank of the active mudsystem. A continuous recording pit level indicator and totaliser, with audible alarm isrequired to monitor the volume of all active pits.

c) A mud return indicator with an audible alarm shall be installed on the flow line.d) Each mud pump shall be equipped with stroke counters.e) The rig shall be equipped with an adequate degasser, to condition gas-cut mud,

installed on the mud active system.f) The 5” OD standpipe manifold lines, connections, valves, and lines from the mud pump

to the standpipe manifold shall have 5,000psi minimum WP with welded connectionsNo thread connections are allowed except for 2" size and below.

g) The standpipe manifold shall be equipped with a connection which can be fully isolatedto fit a 10,000psi cementing line and fully isolated.

h) Two 5" OD x 19mm wall thick stand-pipes and 31/2" ID x 5,000psi WP rotary hoses,with welded connections are required.

i) The rated working pressure of the cementing lines shall be the same as the BOP whichwill not be less than 10,000psi. A cementing line should be connected to the kill lines.

j) The burner booms/flare will be connected to the choke manifold. They will be tied inaccording to the safety regulations in force for the operating zone.

k) An air-operated, skid mounted, high pressure, low-volume testing unit, is required forhydraulic testing of the BOP and manifolds.

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7. CASING AND BOP EQUIPMENT TESTS

7.1. GENERAL PROCEDURES

a) Contract obligations require that all Drilling Contractor's and Company pressurecontrol equipment must be appropriately and regularly tested according tolegislative requirements. Comprehensive test procedures are mandatory and shallbe provided by the Drilling Contractor and authorised by Company.

b) Should any of the above tests identify faulty equipment, drilling operations must besuspended and the well secured, if needed, until the faulty equipment is repairedor replaced.

c) Redundancy of the BOP control system, ensures continued operation of the BOPwhen there is a malfunction in the system or part of the system. However, thisdoes not imply that rig operations continue in the event that there is a failure to theprimary or back-up systems.Derogations of this rule are not allowed on exploration wells or when there arefailures on essential equipment. If malfunctions occur during development drillingor on marginal equipment, the Company Wellsite Drilling & Completion Supervisorand Drilling Contractor Toolpusher/OIM. unanimously may decide to continueoperations, after being properly informed and documented on actual well situationand after having informed the Company operating base Drilling & CompletionManager and the Drilling Contractor Rig Manager.

a) Testing of equipment should be carried out during non-productive time wheneverpossible and be properly planned to ensure that all necessary equipment isavailable, properly installed and in efficient operating condition.

b) All pressure tests shall be performed using water.c) All valves situated downstream of the valve being tested must be in the open

position.d) All pressure tests shall be witnessed by the Company well site Drilling and

Completion Supervisor and Drilling Contractor Toolpusher/Subsea Engineer.

7.1.1. Test Recording

a) All BOP tests, drills, function tests, any malfunctions, repair or maintenance to themud system and well control equipment shall be recorded in the IADC dailyreports and shall be signed by both the Drilling Contractor's Toolpusher andCompany's Drilling and Completion Supervisor on the well site. They shall also berecorded in the Eni-Agip ‘Daily Drilling Report’.

b) All pressure tests shall be recorded on a pressure recorder chart. Recordings willalso include the volumes displaced to reach each test pressure and the volumereturned when bleeding back. Test recording charts and documents shall be kepton board and filed by the Contractor Toolpusher.

c) All test records shall be made available upon request by the CompanyRepresentative or local authorities.

ARPO




7.2. BOP EQUIPMENT TESTS

7.2.1. Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests

All BOP stacks will be pressure tested at their rated WP, prior to use, on test stumps.

7.2.2. BOP Tests After Installation

After installation on the wellhead the following test procedure will be carried out.

1) Pipe rams and annular BOPs shall be tested with open end cup testers to a lowpressure of 300psi (21kg/cm2) and to a high pressure at least equal to the maximumanticipated wellhead pressure.

2) Blind/shear rams shall be tested using blind plug testers to the same pressure asstated above for pipe rams.Where a plug tester is not available, blind/shear rams will be tested against the casingeach time a new casing string has been set prior to drilling out the cement. In this casethe testing pressure will not be succeed 1,500psi (105kg/cm2).

4) In all cases, the maximum test pressure for each BOP test will not exceed 70% of therated WP of the lowest rated item of equipment in the wellhead assembly, casing orpreventer stack assembly, whichever is the lower.

7.2.3. Surface BOP Testing Procedures

BOP stack, choke and kill lines shall be flushed with water prior to testing. If a heavy mud,loaded with large amounts of solids is used, particular care in flushing of lines and valves isrequired.

The wear bushing must be removed.

A cup tester or a blind test plug may always be used for BOP testing.

a) With a cup tester, the following precautions are necessary:• An ‘open ended BOP cup tester’ should be used run in on drill pipe inside the first

joint of casing. An open end cup tester is required to avoid pressurising of thecasing below this point if the cups leak, hence bringing mud flow through the drillpipes to the surface.

• The drill pipe test string must be able to withstand the total load applied on the cuptester as a function of the maximum testing pressure.

• To monitor for any casing pack-off leakage, the casing spool outlet valve must beopen. The check valve in the casing spool will also be kept open by theappropriate needle valve.

b) With a test plug, the following precautions are necessary:• The surface volume pumped during the test shall be carefully monitored to ensure

that the casing is not being pressurised if the test plug seal leaks.• To monitor for any casing pack-off leakage, the casing spool outlet valve will be

open. The check valve in the casing spool will also be kept open by theappropriate needle valve.

ARPO




7.3. FLOATING RIGS

BOP Surface Test

The complete BOP stack assembly shall be tested at the surface on test stumps. All BOPcomponents shall be pressure tested to a low pressure of 300psi (21kg/cm2) and also to theirrated working pressure.

After the surface tests, all clamp and/or studded connections must be checked for tightness.

7.3.1. BOP Tests During And After Installation

1) While running BOP stacks on the riser joints, the choke/kill and booster lines fromsurface to the fail-safe shall be pressure tested to their rated WP.

2) After the BOP stack is landed on the wellhead, a full function test on both pods shall becarried out.

3) All BOP components shall be pressure tested with a test plug to a low pressure of300psi (21kg/cm2) and then to the following pressures:• The lower connector, against one set of pipe rams, to the rated WP of the

wellhead or the ram type preventer, whichever is lower.• All the other components, to a minimum pressure equal to, the maximum

anticipated wellhead pressure, or 70% of the internal yield pressure of theweakest item of equipment, whichever is the lower.

7.3.2. BOP And Seal Assembly Tests After Setting Casing

1) The seal assembly shall be pressure tested to a maximum pressure, equal to themaximum anticipated wellhead pressure, or 70% of the internal yield pressure of theweakest item of equipment, whichever is the lower.

2) The test shall be performed at 500psi (35kg/cm2) increments until the test pressure isreached. The surface volume pumped shall be carefully monitored to ensure that thecasing annulus is not being pressurised and to avoid collapsing or bursting of thecasing.

3) All BOP components, shall be pressure tested to a low pressure of 300psi (21kg/cm2)and to a minimum pressure equal to the maximum anticipated wellhead pressure, or70% of the internal yield pressure of the weakest item of equipment, whichever is thelower.

ARPO




7.3.3. Routine BOP Tests While Drilling

1) All BOP components, with the exception of shear rams, shall be tested to a lowpressure of 300psi (21kg/cm2) and to an high pressure at least equal to the maximumanticipated wellhead pressure.In all cases the maximum test pressure for each BOP test will not exceed 70% of therated working pressure of the lowest rated item of equipment in casing, or BOPpreventer stack, whichever is the lower.

2) Only function the shear rams unless dictated by governmental regulations. Pressuretests of blind/shear rams are not required during this phase.

7.3.4. Routine Subsea BOP Testing Procedures

1) A BOP test will be performed using both pods. If the yellow pod is used for the pressuretest, the blue pod will be used for the function test.

2) Fill the BOP test plug running string to the top with water. The string must remain opento atmosphere during the entire test.

3) The volumes displaced to reach the test pressures and the volumes returned whenbleeding back shall be recorded. The volume and response time for each function willbe compared with the corresponding values recorded during the surface stump test,and any major differences investigated, to detect possible malfunctions.

7.4. BOP TESTING FREQUENCY

BOP test on the test stump:

Every time the rig is moving between wells or any time the BOP stack is pulled for repairduring operation on an actual well for floating rigs.

BOP tests after installing the BOP stack on the wellhead:

After the first installation of the BOP stack on wellhead and any time the BOP is nippledup/down during operations.

BOP tests after setting of casing:

Any time a new casing string is run and cemented.

Routine BOP tests while drilling:

Every 14 days, prior to running a DST or production test assembly, or any time requested bythe Company or to meet with local regulations.

7.4.1. BOP Test Durations

The BOP 300psi low pressure tests will be performed first. They are to be held for a minperiod of 5min. If the BOP does not pass the low pressure test, do not carry out the highpressure test.

It is recommended that high pressure tests are held for a minimum of 10min. The maximumacceptable pressure drop over this 10min period is 100psi.

ARPO




7.4.2. BOP Function Tests

a) All preventers and BOP valves, with the exception of the annular preventer andblind/shear rams preventers, should be operated at least once every shift.

b) Blind/shear rams shall be operated every round trip in the hole.c) The annular preventer shall be operated when the scheduled routine BOP tests

are performed.Pipe rams especially variable bore rams and annular type preventers may be damaged if theyare activated without pipe across the stack, otherwise the rubber packing might be extrudedand possibly damaged. Therefore these tests shall be conducted by closing rams andannular packing on pipe only.

7.4.3. BOP Operating Equipment Tests

Any time the BOP stack is nippled up and after repairing operations, all BOP operatingequipment hoses, control panels, regulator connections, shall be checked and tested to themaximum manufacturer's recommended pressure for closing and opening the BOP's .

7.4.4. Kill lines, Choke Lines And Choke Manifold Tests

Every time tests are carried out on the BOP stack, the associated equipment shall also betested, with water by the following procedure. Choke/kill lines and valves will be tested duringthe BOP tests. The choke manifold will subsequently be tested.

a) Kill and choke lines will be tested from the choke manifold to the hydraulicoperated valve on BOP stack.

b) Each valve of the choke manifold shall be tested individually.c) After the first BOP installation, the equipment shall be tested at their rated WP.

On routine tests, they will be tested at to least the same pressure applied for theBOP test.

7.4.5. IBOP, Cementing Manifold, Pumps And Standpipe Manifold Tests

This equipment shall be tested, with water, every time tests are carried out on the BOP stackaccording to the following procedure.

a) Top drive IBOPs or lower and upper kelly cocks, standpipe and all individualstandpipe manifold valves, up to the relief valve on the mud pumps shall be testedthrough a special test sub, made up on the lower kelly cock and installed on thekelly/top drive.

b) Cementing units, cementing manifold and lines. Each valve shall be individuallytested.

c) Inside pipe shut-off devices shall be tested through a test sub.

After the first BOP installation, the equipment shall be tested to their rated working pressures.On routine tests they will be tested to at least to the same pressure applied for the BOP test.

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7.5. CASING TESTS

Casing pressure tests will be carried out according to the pressure stated in the drillingprogramme. The leading criteria for pressure testing will be the maximum anticipatedwellhead pressure.

In all cases the test pressure will be no higher than 70% of API minimum internal yieldpressure of the weakest casing in the string or to 70% of the BOP WP.

When establishing an internal casing pressure test, the differential pressure due to adifference in fluid level and/or fluid density, inside and outside the casing, shall be taken intoaccount.

Consideration should be taken on the maximum allowable tensile strength of the casingthread considering the relevant tensile design factor.

Each casing shall be pressure tested at the following times:

• When cement plug bumps on bottom with a pressure stated in the drillingprogramme.

• When testing blind/shear rams of the BOP stack against the casing.• After having drilled out a DV collar.

A cemented liner overlap will be positively tested applying a pressure greater than the lea-offpressure of the previous casing. If there is any doubt, an inflow test could be carried out, witha sufficient drawdown to test the liner top to the most severe negative differential pressurethat will exist during the life of the well.

The test pressure shall be held and remain stable for at least 10-15 mins

The test pressure and method for each well are determined on an individual basis and shallbe included in the Geological and Drilling Programme.

7.6. OTHER TESTS WHILE DRILLING

The following tests shall be carried out, only if required by drilling programme under theexpress supervision of Company well site Drilling and Completion Supervisor, which mustindicate the methods and maximum allowable pressures to be applied.

a) Formation Leak-Off Test (LOT).Leak-off tests, or formation integrity tests, can be carried out after setting surface orintermediate casing, to determine the maximum mud weight which can be safelyutilised below that string of casing ( Refer to the Drilling Procedures Manual).

b) Casing Integrity Tests.After drilling inside a casing for about 30-40 days, when expressly required by CompanyDrilling Manager, the casing integrity should be checked, especially in HP/HT wells or incase of deviated holes. Depending on the dog leg severity, this test might be carried outmore regularly (refer to the Drilling Procedures Manual).

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8. BLOW-OUT PREVENTION DRILLS

8.1. FAMILIARITY DRILLS

The purpose of these drills is to familiarise rig personnel with the various equipment and withthe techniques that will be employed in the event of a kick.

8.1.1. Shut-In Drills

These drills are correctly to minimise the time required for the Driller and his crew to close inthe well properly and quickly, and to confirm that all essential tools and equipment areavailable in good operating condition.

The Drilling Contractor's personnel shall conduct drills to close-in the well, in the shortestpossible time, fully comprehending the process.

The Company recommends the following procedure :

1) Without any previous warning an authorised person should activate the alarm signal tosimulate a potential kick situation.

2) The Drilling Contractor's crew should follow the established close-in proceduredepending on the stage of operations at the current time:• ‘On bottom’:

Pick up the kelly or top drive to the correct height, shut down the pumps, thencarry out a simulated well shut-in.

• ‘Tripping’:

Lower the stand into the hole to the correct height and set the pipe in the slips, stab-in afull opening safety valve (lower kelly cock) in the open position, close the safety valve,the carry out a simulated well shut-in.

To train the rig crews, shut-in drills should be planned to also cover the following associatedoperations:

• Pull the BHA out of the hole.• Running casing.• Wire line surveying.• Logging (as well for TLC logging, if any).• Running tubing (single as well as dual completion running).

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8.1.2. Choke Manipulation Drill

The purpose of the ‘choke manipulation drill’, is to provide the drill crews with realistic wellcontrol training and a feel for the equipment and procedures used for killing a well, bysimulating a circulation through the choke manifold under kick condition.

The choke manipulation drill should be carried out before drilling out shoe tracks.

Drilling Contractor’s crew should:

1) Run the bit to above the shoe track.2) Break the circulation and record the RPSP.3) Close the BOP.4) Apply pressure to the well, and simulate a circulation under kick condition using the

automatic power choke and manual adjustable choke5) Record the circulating drillpipe pressure and casing pressure.

Consider applying a low pressure to the casing (say 200psi), and bring the pump up toreduced pump strokes controlling the drillpipe pressure according to a predeterminedschedule.

8.2. EMERGENCY ‘ON-THE-RIG’ DRILLS

The purpose of these drills is to familiarise rig personnel in reacting to emergency situationsthat, depending upon their severity ultimately, may lead to the abandonment of the installation.

8.2.1. Potential Fire On Well And Rig Abandonment Simulation

1) Without any previous warning an authorised person should activate the alarm signal, tosimulate a fire on well, followed by the rig abandonment. The bit should be inside thecasing shoe and not in a troublesome zone.

2) The Drilling Contractor's crew on duty will shut-in the well and hang-off pipe withoutopening the hydraulic valve on the choke and kill lines, then continue with the necessarysteps to simulated rig abandonment by all unnecessary personnel, while the emergencycrew should simulate the fire-fighting procedure.

8.2.2. H2S Drill

1) Without any previous warning an authorised person should activate the alarm signal, tosimulate the presence of H2S. The drill against the H2S effects can be operated at twolevels:• Alarm drills simulating the presence of H2S in the mud.• Emergency drill simulating the presence of H2S in the air, i.e. in the shale shakers

area, on the rig floor, at the mud tanks etc.2) All personnel must wear breathing apparatus and with the exception of the crews on

duty. They must proceed to the windward emergency safe breathing area, while theemergency crew secure the well and simulates the delimitation of the polluted area.

3) H2S drills shall be recorded on the IADC daily drilling report and appropriate companyform.

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8.2.3. Abandon Rig

1) Without any previous warning an authorised person should activate the alarm signal, toabandon the rig due to a potential uncontrollable fire on board, uncontrollable blow-outsituation or damage to rig structure etc.

2) All Personnel except the crews on duty must get ready to abandon the rig. Operationsmust suspended for the time the drill is carried out.

8.3. WELL CONTROL DRILLS

The severity of any well kick can be reduced if it is detected early enough. Crews must beable to recognise the indications of a potential kick and be able to close-in the well properly inthe minimum possible time. These drills are intended to test the driller and mud logger ontheir alertness with regard to an increase in pit volume and to verify that pit level equipmentand indicators are operating correctly.

The Company Drilling & Completion Supervisor shall plan the drills and evaluate theperformance of the rig crew.

No advance notice shall be given that a drill is to be conducted, in order to test the degree ofvigilance being exercise by the driller and the mud-logger.

The time from the moment the drill is initiated, until the crew has reacted shall be recorded,along with the total time needed to complete the drill. All drills and responses shall berecorded on Company Daily Drilling Report and IADC Report. Pit drills shall be recorded onthe Company’s appropriate form.

To complete the drill, The Drilling Contractor’s crew should also fill in the Kill Sheet. SIDPPand SICP values will be provided by the Company Drilling and Completion Supervisor.

8.3.1. Pit Drills

The purpose of this drill is to ensure that the drill crews are familiar with the Soft Shut-Inprocedure implemented in the event of taking a kick while drilling. These drills can beconducted in either, cased or open hole. However, if the drill string is in open hole, the well willnot be shut-in.

1) Without any previous warning an Authorised Person, will change the pit level indicator,to show an increase in mud volume.

2) The mud logger is expected to detect the gain and notify the Driller. The Driller isexpected to perform the following:a) Detect the pit gain.b) Pick up the kelly or top drive to the correct height.c) Shut down the pumps and check the well is flowing.d) Shut in the well as per the established ‘Soft Shut-In procedures’: open the

hydraulic valve on the BOP stack, close the upper bag-type preventer and closethe remote choke.

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8.3.2. Trip Drills

The purpose of this drill is to ensure that the drill crew is familiar with the Soft Shut-Inprocedure to be implemented as described above. The drill shall be performed with bit insidethe casing shoe and not in a troublesome zone.

On floating rigs, the drill should include the procedures for hanging of the string on the BOPstack has per normal practice.

1) An Authorised Person (without any previous warning), will initiate the drill bymanipulating the trip tank indicator or flowline indicator.

2) The mud logger shall detect the gain or incorrect pipe displacement and notify theDriller.

8.3.3. Trip Drill With Drillpipe In The BOP Stack.

The Driller is expected to perform the following:

1) Detect the pit gain or incorrect pipe displacement.2) Lower the stand into the hole and set the pipe in the slips.3) Install a safety valve (lower kelly cock) in the open position.4) Close the safety valve.5) Check for well flow.6) Shut in the well as per the established ‘Soft Shut-In procedure’: open the hydraulic valve

on the BOP stack, close the upper bag-type preventer and close the remote choke.7) Install Gray valve IBOP.8) Open safety valve and prepare to strip in hole with drillpipe.

8.3.4. Trip Drill With Drill Collar Or Tubing In The BOP Stack.

The driller is expected to perform the following:

1) Detect the pit gain or incorrect pipe displacement.2) Lower the drill string tool joint or drill collar connection to a working height (it may be

necessary to install and run a stand of drillpipe or tubing to allow closure of the BOP).3) Set the slips, ensure that no stabiliser or other non slick tool is across the preventer.4) Install the safety valve (lower kelly cock with a crossover) in the open position.5) Close the safety valve.6) Latch onto, pick up the pipe, remove the slips and check for well flow.7) Shut in the well as per the established ‘Soft Shut-In Procedure’, open the hydraulic valve

on the BOP stack, close the upper bag-type preventer and close the remote choke.8) Install a Gray valve IBOP.9) Open the safety valve and prepare to strip in to hole with drillpipe.

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8.4. ACCUMULATOR DRILLS

The purpose of this drill is to minimise the cause of equipment failures, to ensure quick initialclosure times and to check the ability to continue operations in the event of accumulatorpump failure. Accumulator performance shall be proven at the first installation of the BOP onthe wellhead. Thereafter, this drill should be conducted after each casing setting before theBOP pressure tests.

The following test procedure is recommended :

1) Position a joint of drill pipe in the stack. Make sure the tool joint is not access the rams.2) Turn off the accumulator pumps.3) Record the initial accumulator pressure. This pressure should be the design operating

pressure of the accumulator. Adjust the regulator to provide 1,500psi operatingpressure to the annular preventer.

4) Close then open the annular preventer, hydraulic valves on choke and kill lines and thepipe ram preventers for the size of pipe being run.

Closing times shall be less than 30sec for each ram type preventer. Closing time shouldnot exceed 30sec for annular preventers smaller than 183/4” nominal bore and 45sec forannular preventers of 183/4” and larger.

5) Record the final accumulator pressure. The final accumulator pressure shall not beless than 1,200psi (84kg/cm2).

6) Bleed the accumulator pressure down to 1,000psi (precharge pressure). Turn on theaccumulator pumps and record the recharge time. The recharging time from 1,000psito 3,000psi shall be less than 15min.

7) Reposition all the preventer control valves in the normal operating mode.

Equipment that does not meet these requirements, either, has insufficient capacity or is not ingood operating condition and needs repair.

At the end of the drill a function test will be conducted to run the accumulator electric pumpusing the rig emergency generator.

8.5. DIVERTER DRILLS

Because of the limited response time required when diverter systems are employed, theDrilling Contractor shall have written procedures that detail specific emergency action plans.These emergency action procedures should be in operation prior to spudding the well.

The purpose of diverter drills is to reduce to the minimum, the time required for a driller andhis crew to divert the well flow during a kick. Diverter drills shall not be limited to the rig floorpersonnel but shall involve all rig personnel. The drills will be prepared in line with the specificprocedure that will be adopted in the event of a shallow gas kick.

This drill shall be conducted hourly with each crew until the crew is familiar with the drill.

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The Driller is expected to perform the following:

1) Pick up the kelly or top drive so that lower kelly cock is above the rotary table.2) Open the diverter lines, close the diverter element and close the shaker valve (auto

sequenced operation). Check the closing time (for diverter sizes smaller than 20” theclosing time shall be within 30sec, for diverter sizes 20” or larger the closing timeshould be within 45sec).

3) Circulate through both lines.

8.6. DRILL FREQUENCY AND RESPONSE TIMES

8.6.1. Drill Frequency

Training Period

• Shut-in drills.• H2S drills.

These tests shall be carried out on an each shift basis, at the beginning of any new activity,any time experienced personnel are replaced with new recruits, especially when key positionpersonnel are involved such as the Toolpusher, Driller and Assistant Driller. Drills shall berepeated until every crew member gains the correct experience and training.

• Choke manipulation drill. This drill should be carried out prior to drilling out surfaceor intermediate casings string.

Routine Drills

• These drills shall be executed every week. Potential fire on wellsite and/orabandon rig.

• Alert or emergency drills have to be performed weekly and repeated beforeentering the zone where the presence of H2S is suspected, before coring andbefore making DST or a production test when the presence of H2S is, either,predicted or ascertained.

Well Control Drills:

• Pit/trip drills shall be carried out on a shift basis every fortnight. These drills shallbe conducted also when the well is nearing or entering high-pressure zones.

• Diverter drills shall be performed prior to drilling out the conductor string.

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8.6.2. Timing

The time is the most important aspect in shut-in drills and pit drills, and the times required toaccomplish the given task shall be recorded.

The Reaction times that can be considered as satisfactory to accomplish different drillrequirements are detailed below:

• Shut-in drills. One minute from activation of the alarm signal to being ready toclose the bag type preventer.

• Pit drills. Not more than 2.5min from an observable change in drilling fluid volumeto the time the well is closed-in, implementing the soft shut-in procedure.

The correct timing for all other tests will be defined in the Drilling Contractor's Proceduresaccording to the equipment characteristics.

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9. SHALLOW GAS

Shallow gas is defined as gas that is encountered in a well which cannot be closed in as thewell shut in pressure and the hydrostatic head of the fluid in the hole, will probably result information breakdown and cause a subsequent surface blow out.

A shallow gas pocket is always over-pressured with the magnitude of overpressure at the topof the shallow gas accumulation dependent on the thickness of the gas column.

If an anomaly is identified, indicating the possible presence of shallow gas, the primary optionis to drill the well from a location away from the anomaly.

Where there is a risk of shallow gas, The use of a floating vessel or a jack-up in floating modewhich can move efficiently off location, is recommended.

9.1. SHALLOW GAS INVESTIGATION

The well proposals should always include a statement on the probability of encounteringshallow gas. This statement should include an assessment drawn from the shallow gassurvey (if carried out), the exploration seismic data, historical well data and the geologicalprobability of a shallow cap rock.

Even if no gas presence is apparent, it is nonetheless recommended that all measures andprocedures necessary to operate in the presence of shallow gas be implemented in all areaswhere, historically, this event is likely to occur.

Primary well control is the only means to protect the well from blowing out, becausesecondary well control techniques are not normally applicable in top hole drilling operations.

Pilot holes may be drilled, up to the conductor string depth, as part of a preliminary shallowgas investigation programme prior to spudding a well where platforms are planned to beinstalled, in areas with high probability of shallow gas or only a little geological information isavailable.

A rig that can move away safely in case of shallow gas blow out should be used to drill pilotholes (mobile offshore drilling unit or a dedicate soil boring vessel).

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9.2. PRIMARY WELL CONTROL

Primary well control is the only means to protect wells from blowing out, because secondarywell control techniques are not normally applicable in top hole drilling operations.

9.3. RECOMMENDED DRILLING PRACTICES

9.3.1. General Practices

Shallow gas guidelines for drilling operations are discussed in the following sections.

Where possible, floating rigs should be utilised to operate on locations with possible shallowgas because, on balance, the floating drilling unit is safer than a bottom supporter rig whendealing with shallow gas.

Recent experience shows that it is also possible to drill a pilot hole with jack-up rig in a floatingposition to permit a very fast move off from dangerous area in case of shallow gas blow out.

The procedures to move a vessel off location in case of a subsea gas blow-out depend onmany factors (rig type water depth riserless drilling or drilling with marine riser etc.) It isimperative to specify these procedures for each rig and each well. When drilling riserless anda subsea gas blow-out is experienced, it may be possible to pump kill mud andsimultaneously move rig off location a safe distance away from the bubbling gas area. Thedrill string should be disconnected and released immediately, if it prevents the vessel frommoving off location and or when it endangers the rig structure.

The drill string disconnecting and releasing procedure should be available and known to allrelevant personnel in order that they are carried out efficiently without causing any delays inmoving off location.

a) A pilot hole should be drilled in areas with potential shallow gas, as the small hole sizewill facilitate a dynamic well killing operation. The probability of encountering a kick, theseverity of the kick and the chance of dynamically killing the well, determine the pilothole size to be drilled. Small pilot holes will enhance the dynamic well killing capability,and improve log quality. Generally, it is recommended that a drill 121/4” or smaller pilothole is drilled.

b) Restrict the penetration rate (recommended ROP = one joint/hr). Particular care shouldbe taken to avoid an excessive build-up of solids in the hole which could causeformation breakdown and hence losses. Drilling with heavier mud returns could alsoobscure indications of drilling through higher pressured formations and the well maykick while circulating the hole clean. Restricted drilling rates also minimises thepenetration into the gas bearing formation which in turn minimises the influx rate. Anexcessive drilling rate through a formation containing gas reduces the hydrostatic headof the drilling fluid, which may eventually result in a flowing well.

c) All efforts shall be made to minimise the possibility of swabbing. Pumping at theoptimum circulating rate, is recommended for all upward pipe movements (e.g. makingconnections and tripping). In larger hole sizes especially (i.e. larger than 121/4”) it isimportant to check that the circulation rate is sufficiently high and the pulling speedsufficiently low to ensure that no swabbing will occur. A top drive system will facilitateefficient pumping while tripping out of hole operations. The use of stabilisers willincrease the risk of swabbing, hence the minimum required number of stabilisersshould be used.

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a) Accurate measurement and control of drilling fluid is important in order to detect gas asearly as possible. Properly calibrated and functioning gas detection equipment and aseparate flowmeter are essential in top hole drilling. Flow checks must be made beforetripping, any time a sharp increases in penetration rate or tank level anomaly isobserved. When any anomaly appears on the MWD log (if a MWD data transmissionsystem is used) and at any specific depth referred to in the drilling programme (takenfrom the shallow seismic survey), it is recommended to flow check at each connection.

b) A float valve must be installed in all bottom hole assemblies which are used in top holedrilling. The float valve is the only down hole mechanical barrier available.

c) Shallow kick-offs should be avoided in areas with probable shallow gas. Top hole drillingoperations in these areas should be simple and quick, to minimise possible holeproblems. BHAs used for kick-off operations, have flow restrictions which willconsiderably reduce the maximum possible flow through the drill string. Dynamic wellkilling operation will then be very unlikely.

d) A stock of kill mud based on hole size, and for off-shore rigs, water depth and riser sizeshall be prepared before commencement of drilling. The mud weight held in readinessshould be slightly less than the fracture gradient from the sea floor to the shoe of theinitial casing string. The correct mud weight must be determined for the particular areais being drilling.

e) Before spudding the well, a meeting should be held in order to alert key personnel(Drilling Contractor personnel, mud engineer, mud logging operator included) of thefollowing issues:• Risks related to a possible shallow gas blow-out.• Considerations on blow-out development times.• Requirement for quick action to be implemented by personnel involved in

operations.• Drilling control (parameters, levels, gas detectors, tripping, etc.) should be

strengthened for this phase.• For off-shore rigs; emergencies procedures for shallow gas blow-outs (specific

procedures for each rig) must be available and also included, for movable rig,procedures for moving off location.

• For off-shore rig: alert the supply/standby vessels and on-shore base in order tofacilitate fast movement off location and, if necessary, the evacuation ofpersonnel.

• Duties and responsibilities.

Note: The above drilling practices may be modified for development wellswhere it is confirmed that no shallow gas is expected.

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9.3.2. Logging

Information about the presence and depth of possible hydrocarbons can be obtained fromelectric wireline logs or MWD, the latter being the preferred method, since early detectionobviously enhances the safety of the operation.

MWD is the only currently downhole tool capable of shallow gas detection by means ofresistivity and gamma ray recording.

In the presence of normal gradient formation and gas bearing sands the use of MWD, withalmost immediate surface readout, can be valuable in confirming the requirements forspecific measures and procedures to be adopted.

However, in the presence of over-pressured gas pockets, a downhole tool may be of limitedpractical value due to the very fast development of a blow out.

In development drilling, where there is sufficient geological information available fromsurrounding wells to determine that there is no shallow gas, logging may not be required,which avoids pilot hole drilling and hole opening operations. However, the use of a divertersystem is still recommended if there is a risk of colliding with another well or there is apossibility of penetrating charged sands from leaking or poorly cemented casing strings.

Shallow gas detection, with electrical wireline logging or MWD, is not always reliable orconclusive. Excessive hole size and the presence of fresh formation water may mask theshallow gas effect during recording.

9.3.3. Losses

Losses should be avoided during drilling with a diverter system installed. If losses areencountered, they are to be cured quickly using Lost Circulation Material (LCM) or cement.Full returns are to be regained before proceeding to drill ahead. If the losses cannot be cured,possible courses of action include plugging back with cement, either to set casing high or toabandon the hole.

9.3.4. Cementing Operations

The most important item to prevent shallow gas blow-out during cementing job, is anaccurate and correct cement programme.

In addition, and where applicable, it is recommended that the BOP stack remains nippled upwith a small annular pressure maintained during WOC time.

There is no available data to determine the effect of gas blocking agents to stop the gas flow.

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9.3.5. Drilling Procedures

30” Casing

There is no protection against shallow gas in this hole section apart from the dynamic killingoption. Running and cementing the 30” casing in a pre-drilled hole, after having drilled a pilothole, is the recommended technique in areas where shallow gas might be encountered.

An important aspect, which always need to be considered, in floating top hole drillingoperation utilising a marine riser, is the formation strength at the shoe. If the formationstrength at the 30” shoe is considered insufficient the use of the marine riser and divertersystem has to be ruled out and riserless drilling should be employed.

20” Casing:

There are three main methods used to drill 26” hole in shallow gas area:

• Drill pilot hole and open the hole without riser .• Drill pilot hole and open the hole through the riser with underreamer.• Drill pilot hole, pull the riser and open the hole.• Drill pilot hole through a marine riser with return to seabed via a sub sea exhaust

valve (or dump valve) or subsea diverter.

Operation Without The Riser

Riserless drilling is considered to be the safest way to cope with the shallow gas problemsince the vessel can quickly move away from a subsea blow-out. The risk of riserless drillingincreases with decreased water depth. The presence of the water ensures that somehydrostatic pressure is always available to act against the shallow kicking formation. Thepossibilities of riser collapse and borehole unloading are eliminated. The primarydisadvantage involved with drilling in shallow water, without a marine riser, is that a gas kickmay result in reduced rig buoyancy due to the presence of a gas bubble in the water beneaththe rig.

However, case histories show that the effect of buoyancy loss as a result of a sub sea gasblow-out does not represent a major risk to floating vessel. Also because ocean currents areusually sufficiently strong to carry all of the gas safely away from the rig.

Water depth has some influence on buoyancy loss, but it has greater influence on vesselinstability, especially at very shallow water depth.

A minimum water depth cannot be given since many variable factors should be consideredfor each case.

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Pilot Hole Opened Through The Riser With An Underreamer

There are various advantages, unrelated to well control, when using a riser. Using a riserallows treatment of the returning mud stream, considerable saving in time and money,formation samples and gas samples may be examined and evaluated at surface as drillingprogresses, the mud gradient can help to control the well.

Use of a marine riser while drilling shallow holes does pose some disadvantages; the gasmay cause the mud in the riser to unload, this results in decreased hydrostatic pressureacting against the kick which in turn allows the influx rate to increase. Higher pump rates arenecessary to outrun kicks having higher rates of fluid influx. Unloading the mud in the riseralso allows the hydrostatic pressure exerted by the water outside the riser to act against riserwall, thus raising the possibility of riser collapse. If we attempt to control a shallow kick by acolumn of heavy mud above the kick zone, the possibility exists that an excess of heavy mudin the riser may cause lost circulation and an even worsen the conditions.

The operative time necessary to run and to pull-out the riser.

When drilling with a riser consideration must be given to riser release and moving off locationif a shallow gas blow-out occurs.

9.4. DIVERTER SYSTEM OPERATING PROCEDURES

The diverter system shall be used for all wells unless there is clear information of theabsence of potential shallow gas.

Diverting Shallow Gas In An Emergency

The conductor pipe diverter system is only intended to divert flow away from the drill floorwhen there is a kick. It should never be completely closed-in and used as a BOP in anattempt to control the well as they are not designed to hold pressure but only to direct flowoverboard.

Diverting shallow gas is a well emergency.

The blow out contingency plan should be implemented as soon as it becomes apparent thatthe well cannot be dynamically killed.

Specific contingency plans for dealing with emergencies which may occur during diverteroperations should be prepared for each rig and each well but should address the following:

• Shallow gas meeting for all the crew.• Diverter drills and exercises.• Shut down procedure for ignition sources.• Shut-in the well, if this a dynamic killing failure, evacuate all the personnel

excluding the emergency team where there is a case of diverter failure evacuateall the personnel.

• Alert the office base (An office based supervisor should be present on location ifdiverting shallow gas is a possibility).

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For a movable rig:

• Disconnecting procedure for the riser;• Closing procedures for watertight doors and hatches;• Procedures for releasing the drill string from the drill floor;• Procedures for moving the rig off location (pulling by anchors or by a towing

vessel).

9.4.1. Diverter System

There are three main types of diverter:

• Surface diverter.• Marine diverter.• Subsea diverter. which is not common and available only on few rigs.

Note: Published studies show that diverter failure rates range from 50% to 70%of all application with the consequence of a very high risk of explosionor/and fire on the rig.

Specific causes of diverter failures are:

Erosion Is primarily dependent on fluid velocity, abrasiveness of theentrained solid and the angle of impact of the solids againstsystem components. Erosion can be mitigated by reducing oneor more of these factors. Erosion failures generally have beendue to undersized lines and flow path upset that causesturbulence. The minimum required nominal ID of diverteroutlets lines is considered to be 12”. Bends, bore size changesand flow path discontinuities produce high particle impactangles and local increases in velocity.

Blockage Many shallow gas flows contain large quantities of debris(rocks, sand, etc.) and there have been several documentedcases in which this debris has packed off at bends in thediverter lines or other obstruction. The pressure surge due tothe blockages resulted in failure of other components.

Poor ComponentSelection

In some cases, valves and other key elements have beeninstalled that could not handle the dynamic condition, pressuresurges and debris laden flow. Low pressure, butterfly orguillotine type valves have failed to operate as required orcaused line blockages. Gate valves, in general have hadproblems with trash in the guides. Welded flange or hubconnections are mandatory on diverter systems. Quickconnections in diverter lines are not allowed. Diverter linesshould be straight and properly anchored.

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Slip Joint PackingLeaks

The slip joint packing element has historically been a source ofproblems during shallow gas flows on floating drillingoperations. The packing elements have then typically failed dueto the flowing pressure exceeding the sealing capabilities of thebladder or due to the bladder seizing to the riser and rupturingat the increased inflation pressure.

High Flow Rates

In some cases inadequately supported diverter piping has been damaged from vibrations andwhipping caused by high flow rate.

The insert type diverter cannot divert the flow if the pipe is out of the hole. This type of unitcannot close on open hole and is not be possible to strip back into the well using the bladdersealing element common to the insert type diverter.

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9.4.2. Diverter Test (before start of operations)

Before start of drilling operations perform a diverter test as the following:

1) Close the diverter on 5” DP (check the closing time, this time depend on the divertertype, usually, smaller then 20” within 30sec, 20” or larger within 45sec).

2) Circulate through both lines.

9.4.3. Diverter Procedure

At the first sign of flow, the following actions are required:

1) Pump the original mud or water immediately at maximum pump rate.2) Stop drilling.3) Activate the diverter function (start to evacuate the non essential personnel).4) If the well is still flowing, pump heavier mud at maximum pump rate.5) If the well continues to flow after the heavier mud has been pumped, carry on pumping

other mud or water at the maximum rate;

Further dynamic kill attempts may be as follows:

1) Mix heavier mud whilst pumping mud or water at maximum rate.2) Pump heavy mud at maximum rate.3) Repeat sequence if dynamic killing is still unsuccessful, but do not use excessive mud

weight which could result in formation breakdown.

Note: Shutting down the pumps to check for flow may result in an even greaterinflux flow rates. Continuous pumping is recommended especially if thereis a suspicion of flow. Historical data shows that once a blow out start witha high flowrate it is very difficult kill the well by dynamic kill techniques.An improved chance of success is for the dynamic kill operation to beinitiated as a early as possible at the first suspicion of flow.

Recent investigations indicate that erosion can be reduced in the diverter by injecting waterahead of the diverter as a dry gas condition is the worst case for erosion. Based on thisconsideration it is always recommended, where possible, to pump water via the kill lineespecially where it is not possible to pump via another route.

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10. H2S DRILLING PROCEDURES

The below topics represent Eni Agip general guideline to operate in H2S environment.

It is compulsory that the Drilling Contractor has an ‘Emergency Safety Plan’ including aspecific procedure for the presence of H2S.

10.1. EMERGENCY SAFETY PLAN

This document will be submitted to Eni-Agip and shall comply with the requirements of thebid. It shall be in accordance with the regulations in force in the Country where operations areto be carried out and shall be an accurate tool aimed at respect to and safety of human life. Itwill be analysed by Eni-Agip expert engineers.

The document shall be constructed specifically for each rig and updated for each well, givingdetailed information concerning:

Land rigs, Jack-ups and Fixed Platforms

• Location, type and setting of the alarms.• Location of individual protection and first aid equipment.• Personnel duties (for each professional position).• Meeting points.• Composition of the Emergency Team.• Evacuation (time and manner of evacuation shall be described clearly).• Frequency and manner of drills.• Use limits, control and extinguishing of free flame.

Floating Rigs

• Riser disconnection.• Rig moving using its own propulsion system, anchoring lines and/or supply

vessels.• Procedures for drill string abandoning in hole.

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10.2. DUTIES OF PERSONNEL

The Company will ensure that on board H2S briefings provide clear instructions on how thealarm is raised and who is responsible to take action.

Anyone on board who believes that they can smell H2S (like rotten eggs) must immediatelyreport this to the senior drill floor personnel or Production Test Supervisor during well testing.Raise the alarm so that the area can be investigated by authorised personnel, suitablyequipped with a respirators and using suitable portable detection equipment.

10.2.1. Manager Or OIM

a) The Manager in charge of the operations or the OIM shall arrange the ServiceOrders and the Emergency Plan bearing in mind the procedures Containedherein.

b) He will agree with the Company on the Emergency Plan which shall comply withthis document and distribute it to the supervisor and responsible personnel.

10.2.2. All Personnel

a) Shall be familiar with all the instructions and procedures contained in theAppointments and Emergency Plan arranged by the Manager in charge of theoperations or the OIM.

b) Shall be familiar with any equipment shown during the safety drills.c) In emergencies, they must first preserve their own safety.d) Must aid injured personnel exposed to toxic gas.e) Must follow their supervisors instructionsf) Must not panic.

10.2.3. Eni-Agip Drilling and Completion Supervisor

a) Shall ensure that any instruction and procedure contained in this document and inthe ‘Safety and Emergency Plan’ prepared by the Drilling Contractor are followed.

b) Shall pay attention that all personnel participate in the safety drills when apotentially H2S bearing formation is to be drilled and that the meeting is reported inthe IADC daily drilling report.

c) Ensure that drills are performed regularly.d) Will check the wearing and location of H2S equipment, their compliance with the

standards required for the rig (that in a sour area shall not be less than thatspecified in appendix A). He shall evaluate its functioning, during drills, and shallreport in the minutes any suggestion for improvements.

e) Shall evaluate the situation when gas is detected and take corrective action.f) Will keep in contact with the Eni-Agip District Drilling Superintendent.

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10.2.4. Drilling Contractor's Toolpusher

a) Will represent the Drilling and Completion Supervisor if he is disabled.b) Will check that all personnel on board have had a medical examination and

ensure that all personnel have received proper safety instructions and areequipped with functioning breathing apparatus.

c) Is responsible for the control and maintenance of the safety equipment.d) Is responsible for the availability, condition, efficiency, location of, and expiry date

of all H2S equipment.e) Is responsible for the availability and efficiency of the means of communication

(radio link, telephone, interphone, walkie-talkie).f) Is responsible for Contractors' personnel to be familiar with and know how to

carry out their own duties in dangerous situations.g) Is responsible for emergency drills scheduling and performance, and arrange for

the proper orders to be given to ensure continuity and functionality of operations.

10.2.5. Driller

a) Will replace the Eni-Agip Drilling and Completion Supervisor and PlatformManager or the Toolpusher in their duties if both are disabled.

b) He will ensure that the placing the rig on safety status, if the evacuation of all,personnel should be necessary, in accordance with the ‘Safety and EmergencyPlan’ prepared by the Drilling Contractor.

c) Is responsible for the drilling team’s safety and is the Emergency Team’smanager.

10.2.6. Mud Engineer

a) Will conduct the ‘Gas Garret Train Test ‘ or the ‘Hatch Test’.b) Will treat the mud with ‘H2S Scavenger’.

10.3. OPERATING CONDITIONS AND PROCEDURES

There are two different operating alert levels:

• Condition 1 - Pre Alarm.• Condition 2 - Alarm.

10.3.1. Condition 1 - Pre Alarm

Condition 1 is when H2S is present in the air - i.e. detected in the shale shakers area, on therig floor or at the mud tanks in quantities between 10ppm and 20ppm inclusive.

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Typical situations are:

• H2S is found in concentrations ranging from 10 to 20ppm.• H2S is found in the air, and phenomena such as ‘drilling break’, ‘kick’ or lightening

of the mud indicates the ingress of formation fluids into the bore hole.• Recovery of a core from a layer which is known to be H2S bearing (see the

relevant specific procedure).

Operating procedure

1) When the presence of H2S is detected, the Mud Logging Unit Operator mustimmediately inform the Driller, the Eni-Agip Drilling and Completion Supervisor and theDrilling Contractor's Toolpusher.

2) Acoustic and visual alarms must start automatically in the Dog House when the H2Sconcentration detected by a single sensor exceeds the 10ppm threshold.

3) A similar alarm must also be present in the Mud Logging Unit. Such signals(appropriately loud and visible) must be activated in such away as to be easily seen andheard over the entire location ( Refer to Appendix A).

After having checked the situation, the Eni-Agip Drilling and Completion Supervisormust:

• Verify the operations on going in the well and consider whether it is necessary toclose the BOPs;

• Give instructions to the Mud Engineer to treat the mud with an ‘H2S Scavenger’;• Advise the Drilling Superintendent or the Company's District Representative on

duty about the occurrence of a moderately dangerous situation and report everyfurther development;

• Re-check and test all H2S sensors• Take proper actions as per “Safety and Emergency Plan “ prepared by the drilling

contractor.

The Drilling Contractor's Toolpusher must:

• Instruct a Safety Expert (Assistant Driller) to check the H2S concentration bymeans of portable detectors.

• Check the wind speed and direction, in order to define the areas of potentialdanger.

• Activate the ventilation system on the rig floor.• Take proper actions as per the ‘Safety and Emergency Plan’ prepared by the

Drilling Contractor.• Notify Eni-Agip Drilling and Completion Supervisor the results of every control and

the measurements.• All personnel shall act in accordance with the ‘Safety and Emergency Plan’

prepared by the Drilling Contractor.

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10.3.2. Condition 2 - Alarm

Condition 2 is when H2S is detected in the atmosphere in quantities exceeding 20ppm in theshale shakers area, on the rig floor or at the mud tanks

Typical situation are:

• H2S is present in the atmosphere in concentrations greater than 20ppm.• Although the sour gas concentration of 30ppm is not dangerous to human life, it

indicates a ‘Level of Concern’.

Operating Procedure

1) When an H2S concentration greater than 20ppm is detected, the Mud Logging UnitOperator must immediately inform the Driller, the Eni-Agip Drilling and CompletionSupervisor and the Drilling Contractor's Toolpusher.

2) An acoustic and visual alarm must automatically turn on in the Dog House.3) Similar alarms must also be present also in the Mud Logging Unit. These signals must

be visible and audible from the whole location (see Appendix 2).4) For offshore installations, air aspirators for ventilation living quarters, engine room and

all closed rooms shall be closed-in and all personnel shall act in accordance with the‘Safety and Emergency Plan’.

The Eni-Agip Drilling and Completion Supervisor must:

1) Give instructions to restore normal operating conditions (employing ‘key personnel’).2) Advise the Drilling Superintendent or the Company's District Representative on duty

about the existence of a the dangerous situation and report every further development.3) Submit to all H2S sensors further tests by means of portable detectors4) Take proper actions as per “Safety and Emergency Plan “ prepared by the drilling

contractor.

The Drilling Contractor's Toolpusher must:

• Instruct a Safety Expert (Assistant Driller) to check the H2S concentration bymeans of a portable detector and determine the quickest and safest escape way.

• Check wind speed and direction in order to define the areas of potential danger.• Turn on the rig floor fans when they are foreseen.• Instruct to light the flare ‘pilots’.• Inform the Eni-Agip Drilling and completion Supervisor about the results of every

inspection and measurement.

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The Driller must:

1) While the pumps are working, lift the kelly or the top drive till the lower kelly-cock isabove the rotary table.

2) Stop the mud pumps.3) Open up the choke line hydraulic valve.4) Let the drilling string lean on slips.5) Close BOP.6) Close the adjustable choke on the choke manifold.

All Personnel Not Engaged On The Rig Floor, must

• On onshore rig wear the breathing apparatus (i.e. 10min) Automatic PositivePressure Escape Breathing Apparatus); go to the emergency safety area,windward (previously assigned by Drilling Contractor's Toolpusher) and wait forfurther instructions.

• On offshore rig take proper actions as per “Safety and Emergency Plan “prepared by the drilling contractor

10.3.3. Core Recovery In Presence Of H2s

After coring in a H2S bearing formation, it is necessary to wear the Cascade System masks(if available ), or Self Breathing Apparatus with 30-45min bottles, during the whole corerecovery operation, both using a rubber type core barrel or a inner tube core barrel.

A specific section of the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor shallbe dedicated to coring operations.

10.3.4. Well testing in presence of H2S

The risk of encountering H2S must be assessed from available information relating to thecurrent well and other wells in the area.

Danger signals must remain displayed while also carrying out production testing where apresence of SO2 greater than 5ppm is expected (due to the combustion of layer fluids).

H2S Emergency Provisions

In the event that the occurrence of H2S is a possibility, provisions must be made as follows:

1) Detection - any H2S fixed or portable detectors which may be required in addition tothose already on board.

2) Wind Direction - indicators such as pennants or socks will be positioned in at least 4locations such that the movement of H2S can be foreseen and its impact on escaperoutes/ systems and support vessels/helicopters can be assessed.

3) Any person working on a rig that is drilling in a known H2S area or which encountersH2S while drilling must be clean shaven.

The Production Superintendent and representatives from the Drilling and Safety Departmentsmust inspect the rig and ensure that a safety meeting has been held before the well testoperations start.

General Procedures

The requirements below must be reconciled with the Drilling Contractor’s onboard equipment

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and emergency procedures to ensure that they cover all the points addressed. In the eventthat there are deficiencies they must be dealt with to ensure that the overall provisions are atleast equivalent to the requirements of this manual.

Detection

Detection is accomplished by smell, mud analysis, fixed detectors and hand held detectors.Only the fixed detectors will automatically provide an alarm, all other detection methodsrequire personnel to raise the alarm.

Brine/Mud Analysis

In the event that brine/mud analysis shows the presence of H2S, the logging engineer willimmediately raise the alarm indicating the level of gas. He must be provided with adequatemeans of communication.

Personal Monitor

Any detection of H2S by personal monitor must be reported immediately to the senior drill floorpersonnel or Production Test Supervisor during well test operations and the OIM, giving thelocation of detection and the concentration measured.

Fixed Detectors

Provision of the fixed detectors must be such that detection of H2S will result in a suitablealarm being raised in all areas manned during drilling or well test operation, i.e. in the mudtreatment room and in the control room, and also give the detector position and theconcentration detected.

Safe Breathing Areas (offshore rigs)

The OIM will designate at least two Safe Breathing Areas (SBAs) of which one will be in theopen air upwind of any incident. The second SBA will be inside the accommodation in thegallery/cinema/recreation area. An H2S detector will be provided in the inside SBA and mustbe switched on when the alarm is given. If deemed necessary, a second open air SBA will bedesignated to ensure that at least one SBA will be upwind of any incident.

H2S Detection While Tripping

Prior to pulling out of the hole, circulate the brine/mud system.

Circulating

All drill floor and mud room personnel will wear SCBA and be masked up (fireman’s sets ortied into the cascade system) immediately. At the same time the mud/gas separator(degasser) will be started and all non essential personnel will be warned to stay away fromthe drill floor and mud treatment areas.

Mud logging personnel will inform the Toolpusher and the OIM when the trip gas is up andwhen the H2S level falls below 10ppm.

Logging

When pulling out of the hole, all tools and cable must be washed with scavenger and sprayinhibitor.

Persons handling repeat formation tester (RFT) samples/chambers must wear SCBA untilthe chamber has been vented and purged.

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Flow Testing

During this phase (time from first opening of test tools until tools are recovered to surface)H2S will be produced to the surface for the first time with consequent increase in risk. Tocounter this the following precautions are required:

1) Before well test operations take place:2) The onshore Drilling Manager/Drilling Superintendent, Snr Production Engineer, Workover

Superintendent and Safety Superintendent in consultation with the Rig OIM, the offshore Eni-Agip Senior Drilling Supervisor and Production Test Supervisor must agree whether or not itis necessary to specify any in stream concentration of H2S at which the well test crew andother essential personnel involved in well test operations must mask up.

3) A safety meeting prior to opening the well must be held to inform all personnel of theincreased risk of the presence of H2S.

4) All testing equipment and systems must be capable of withstanding the effects of H2S.5) All critical activities such as the first opening of downhole tools must be performed in daylight.6) All personnel considered by the OIM to be non-essential must be taken off the rig before the

start of the test and remain off until after the end of the test.

7) During the testing period, all off duty personnel shall be restricted to the accommodation areaand their movements will be controlled by the OIM.

8) At the production of first hydrocarbons to surface, essential personnel will all wear SCBA andbe masked up. Masks will be worn until the level of H2S being produced has been establishedat the choke or at the separator.

9) In stream H2S levels will initially be monitored every 10min for changes, initially, and thereafterat periods agreed by the OIM, Production Test Supervisor and H2S technician.

10) When H2S is present in the flowstream, the well will be shut-in if the wind speed is less than 5knots. In any event, it is the responsibility of the OIM to decide if the wind speed or directionpresents a hazard which requires the suspension of testing.

11) Testing personnel must wear SCBA and mask up prior to operating or performing work onequipment or systems which have contained H2S, e.g. changing chokes, operating flowheadvalves, using bubble hoses, taking separator samples, etc.

12) No open tanks will be used for collecting flow products. Surge tanks and separators will beequipped with vent/overflow lines which discharge at the flare.

13) Background levels of H2S will occur from various sources such as flare residue, valves,flanges, couplings etc. This level must be monitored for increases so that preventativeactions can be taken.

14) The installation must be monitored for the presence of sulphur dioxide (SO2) using portablemonitors.

15) When the test tool retrieval gets to within five stands of tubing from the first test tool, i.e. thereverse circulating valve, all rig floor personnel will wear SCBA and be masked up until thetesting string has been broken down, sample chambers have been emptied and purged andslip joints stroked.

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10.4. EMERGENCY CONDITION

An ‘Emergency Condition’ is termed any situation where, according to the Eni-Agip Drillingand Completion Supervisor and Drilling Contractor's Toolpusher, there is a significant anduncontrollable air pollution from H2S and/or where it is impossible to keep well operationsunder control using the equipment available on the rig site.

Some of the typical situations are :

• BOP malfunctioning while controlling a kick.• Blow-out ‘behind’ the surface casing.• Blow-out inside the drilling string (with rams closed).• The sour gas concentration reaches a value of LC 50 (Lethal concentration).

LC 50 has been defined to correspond to an H2S concentration of 444ppm undera prolonged inhalation of 4hr.

Similar for SO2, the LC 50 represents a concentration of 2,520ppm under aninhalation of 1hr (The data are taken from the ‘Dangerous Properties of IndustrialMaterials’, published by Van Nostrand Reinhold, New York).

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10.4.1. Emergency Operating procedure

When the alarm hotter rings constantly:

1) On onshore rigs, all personnel not engaged on the rig floor must wear the breathingapparatus (10 min. Automatic Positive pressure Escape Breathing Apparatus), proceedto the emergency safe area windward and wait for further instructions. After setting thewhole rig to the safety condition, the motorman must stop all engines and start theemergency generator to serve lights, accumulator and radio bridge.

2) On offshore rigs, the Eni-Agip Drilling and Completion Supervisor alert supply vesselsavailable in the area, to approach the rig on the windward and initiate proper actions asper the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor;

After having ascertained the emergency situation, the Eni-Agip Drilling andCompletion Supervisor must:

1) Advise the Drilling Superintendent and the Company District Executive on duty, or theDistrict Telephone Operator, about the existence of an emergency condition.

2) Report to the Drilling Superintendent or to the District Representative on duty (eitherdirectly or through the appointed person) about the actual situation, the actions takenand the future measures to be agreed upon. The information is to be transmittedthrough the enclosed forms (Appendix A). It will allow to state whether the hazard areacan be delimited or not on onshore rigs.

The Drilling Contractor's Toolpusher Or OIM. must:

1) On onshore rigs, arrange the vehicles for the evacuation of personnel windward;2) On onshore rigs, ascertain that all personnel have left their working place and moved

away, staying windward, at least past the distances indicated in the table 10..

Gas Output(1,000 Nm3/day) Concentration H2S (%) Radius of danger area (m)

3,000 10 1,2001,000 10 6003,000 1 3001,000 1 1603,000 0.1 801,000 0.1 40

Table 10.a - Radius of Danger

Note: The danger area radius is calculated in calm wind conditions ( <<1 m/sec).

4) By means of a walkie-talkie, make sure that the evacuation is completed.5) Organise monitoring of the area as indicated by the table 10. above on onshore rigs.6) On offshore rigs, act in accordance with the ‘Safety and Emergency Plan’ prepared by

the Drilling Contractor.7) The Emergency Team shall act in accordance with ‘Safety and Emergency Plan’

prepared by the Drilling Contractor and secure the well (as per the ‘Well Control Policy’issued by Eni-Agip). The Emergency Team shall remove or deactivate any explosivemixture or agent present on site.

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The Drilling Superintendent or the Company's District Representative on duty, as soon as heis informed about the events and has agreed with the Eni-Agip Drillingand CompletionSupervisor at the field on the immediate actions to be taken, must:

1) Inform the Drilling and Completion Manager of the district.2) Proceed to the location and join the Emergency Team as Manager of operations, until

he will be relieved by the Emergency Manager from the San Donato Milanese Headoffice.

As soon as he is informed, the Drilling and Completion Manager of the district must:

1) Give out instructions according to the ‘Eni-Agip Emergency Plan’.2) Advise the District Manager as well as the Eni-Agip Head Office in San Donato Milanese

and, if necessary, request co-operation from Districts or Head Office.

10.5. ACTIONS TO TAKE FOR THE CONTROL OF AN EMERGENCY

Since different occurrences require to be approached differently, it is not possible to detail anygiven situation. Below we make a list of the actions, responsibility and duties of theEmergency Team.

10.6. EMERGENCY TEAM

Eni-Agip Drilling and Completion Supervisor and Contractor Toolpusher or OIM, after fulfillingthe duties previously said, shall subdivide the Emergency Team in groups that shall follow upthe well behaviour and evaluate the gas rate, actions to be taken utilising the rig equipment,measure the H2S concentration with portable apparatus, etc.

They will follow the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor and willbe equipped with:

• Portable sensors (1 for each group).• Calourimetric phials for H2S.

• Calourimetric phials for SO2.

• Walkie-talkie (with earphones and laringophones).• Bottles for self contained breathing apparatus.

They will keep contact with Eni-Agip Drilling and Completion Supervisor and ContractorToolpusher or OIM continuously, reporting any developments of the situation.

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10.7. DELIMITATION OF THE POLLUTED AREA (ONSHORE)

• It is the specific duty of the emergency team (in on-shore installation) to determinethe borders of the polluted area.

• The changes in weather or well situation may entail a change in the radius andextent of the danger area.

• For the above reason it is hugely important to mark the borders of the pollutedarea which must be systematically updated.

The situations where the area markings are lost or its limits trespass the location perimeterare particularly serious.

In this case the Eni-Agip Drilling and Completion Supervisor (who will be constant radiocontact with emergency team and the District office) will inform the Emergency expert/Drillingand Completion manager and wait for instructions.

10.8. PERSONNEL TRAINING

All personnel, engaged in the field, must have knowledge of the procedures set forth hereinand participate in the relevant drills.

This rule refers to Eni-Agip personnel as well as to the Drilling Contractor's and any ServiceCompany's personnel.

Training drills shall be performed regularly while drilling is ‘safe’, i.e. before entering aformation which is potentially H2S bearing.

Note: To be successful, the emergency operation requires the presence on therig of personnel highly qualified to work in hazardous conditions andwhom have to attended the subject training course before field training.

10.8.1. Safety Meeting

During a ‘Safety Meeting’ which will take place before stating the potentially dangerousoperations are started, the training of personnel by the personnel mentioned in the ‘Safety AndEmergency Plan’ prepared by the Drilling Contractor will be achieved by dealing with thefollowing topics:

a) The dangers of hydrogen sulphide to be explained in detail.b) Field logistical distribution, location of breathing apparatus, use of wind socks ,

movement of personnel towards the safe emergency area.c) Use of:

• Breathing apparatus• H2S portable detectors• SO2 portable detectors• Combustible gas detectors• Revival equipment• Portable extinguishers• Alarm system.

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a) Personal practice in assistance of people and surveillance (to prevent accidentsand to give aid promptly).

b) Introductions to personnel if there is unexpected H2S rush:• Do not to panic• Do not to breathe (Before donning a breathing apparatus)• Wear protection breathing equipment (10 min. Automatic Positive Pressure

Escape) and abandon the polluted area.• Move to the indicated emergency safe area and wait for instructions.• Those who have a breathing apparatus (30-45 min. Self Contained

Breathing Apparatus), must wear it, and return to the polluted area to rescueanyone in difficulty.

10.9. H2S PREVENTION DRILLS

Prevention drills are to be recorded on the IADC daily drilling report and in the H2S Drill form (Refer to Appendix A), enclosing a copy of the minutes of the meeting with name and signatureof all participants, as well as any remarks).

H2S prevention drills have two levels:

• Alarm Drills• Emergency Drills

10.9.1. Alarm Drills

When the acoustic alarm are sounded (simulating the presence of H2S), all personnel shallbehave in accordance with the ‘Safety and Emergency Plan’ prepared by the DrillingContractor. To illustrate this, typical a drill scheme is given below :

a) All personnel (‘key personnel' excepted) must proceed to the windwardemergency safe area.

b) The Derrickman must light the flare pilots and proceed to the mud pit area.c) The Toolpusher and the Driller are to check that the portable detectors are fully

operational.d) The Toolpusher must check wind velocity and direction.e) The Assistant Driller and the electrician must measure the H2S concentration in

the leeward area, using the portable detectors.f) After e) above that, three Floormen, wearing breathing apparatuses(30-45 min.

Self Contained), shall return to the rig floor together with Driller, Assistant Drillerand Derrickman, and pull out two drill pipe stands. The Derrickman must climb tothe derrick deck, together with another person, both wearing an breathingapparatus.

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10.9.2. Emergency Drills

When the continuous alarm siren, signalling an emergency is sounded:

a) All personnel shall immediately wear the breathing apparatus (10min AutomaticPositive Pressure Escape) and, except the personnel engaged on the rig floor,proceed toward the life boats or in the safe windward area;

b) The Driller shall stop any operation at the rig site, leaving the drill string on theslips with the kelly installed;

c) The Motorman shall stop up engines and start the emergency generator;d) The OIM or the Toolpusher shall check that H2S and explosive mixture portable

meters are fully functional.

10.9.3. Drill Frequency

Alert and Emergency Drills shall be carried out in accordance with the ‘Safety and EmergencyPlan’ prepared by the Drilling Contractor. However, in areas where H2S presence is expectedor confirmed, they have to be carried out weekly. They also have to be performed wheneverpulling up into the shoe and repeated before entering any expected H2S bearing levels e.g.,before to perform coring, DST or production testing.

Results shall be reported on the IADC daily drilling report and on the dedicated form (Refer toappendix A). It is important to measure the time required for personnel gathering and beingaccounted at the meeting point.

10.10. H2S DETECTION SYSTEM

The drilling platform or rig will be equipped with a fixed H2S monitoring system, capable ofrecognising the presence and concentration of the previous stated levels of.

10.10.1. H2S detection in air

A box for the detection of H2S in air must be installed in the ‘Dog House’.

The system will consist of a unit capable of measuring gas concentrations in air at four variessites (shale shakers, rig floor, bell nipple and mud pit) and activate the sound alarm and lightswhen the danger threshold is reached. For off shore drilling units the sensors shall bepositioned, as the very minimum, at the following locations:

• All air inlets to closed rooms• Shale-shaker area• Pumps room• Rig floor• Below the rotary table• Mud pits• Cellar deck/moonpool.

During production testing additional sensors must be placed near the separators, heater, etc.

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10.10.2. Sensor Ranges

The system measuring capacity must be 0-50ppm in air.

Danger thresholds are set as follows:

• Pre Alarm: for a concentration between 10ppm and 20ppm in air;• Alarm: for a concentration upper of 20ppm. in air

The alarms set up by the ‘Dog House’ and the ‘Mud Logging Unit’ must operate automatically,but also allow manual operation.

Three portable detectors must be available on the rig and provided with colourimetric vials forthe detection of H2S and SO2. These detectors must be used in areas not monitored by thefixed system and if the gas concentration exceeds measuring limits of the fixed sensors.

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10.11. BREATHING APPARATUS AVAILABILITY

10.11.1. Standard Equipment For All Rigs

The standard land rig must include the following individual protection means:

• Breathing apparatus (10 mins Automatic Positive Pressure Escape BreathingApparatus).

Apparatus of the overpressure type with supply of 45 spare cylinders, capable of providing anautonomy of nearly two hours to emergency team personnel.

They must be distributed within the rig as indicated by the following appendix A

30 - 45 Minute Self Contained BreathingApparatus

10 Minutes Automatic Positive PressureEscape Breathing Apparatus

Drilling Team 5 Drilling Team 5Motorman 1 Motorman 1Mud Engineer 1 Mud Engineer 1Mud Logging Unit 1 Mud Logging Unit 2Eni-Agip Supervisor 1 Eni-Agip Supervisor 1Toolpusher 1 Toolpusher 1Tourpusher 1 Tourpusher 1Extra Supply 4 Assistant Motormen 1TOTAL 15 Electrician 1

Eni-Agip Geologist 1Store Yard team 3Gusts 3Extra Supply 9TOTAL 30

Table 10.A - Breathing Apparatus Distribution

The minimum standard for equipment on all drilling platforms shall include the followingindividual protective breathing apparatus:

• Protecting Breathing Apparatus (10min Automatic Positive Pressure Escape) thequantity equal 120% of the number of people that can be accommodated onboard.

• Self Breathing Apparatus of a quantity equal to 120% of the total number ofpersonnel in the emergency team and provided with minimum of 3 spare bottleseach.

According to the list of standard equipment (Refer to Appendix A), supply vessels and boatsassisting the drilling unit operating in H2S area, shall be equipped with the following individualmeans of protection:

• Breathing Apparatus of a quantity equal to 120% of the number of crew andprovided with a minimum of 3 spare bottles each.

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10.12. CASCADE SYSTEM

Where the H2S risk is high and protection means are used frequently, the use of apparatuseswith 30min air reserves would be impractical and require rig personnel to maintain a carefuland precise check of the air available in the cylinders.

To overcome such problems drilling rigs or platforms must be equipped with a fixed systemor Cascade System for the supply of the necessary air, in addition to the standard equipment.

Rig personnel shall connect themselves to the system at point appropriately arranged, usingthe umbilical hose provided with a rewinding automatic device (some of which may be as longas 20m).

Connections for umbilical hose and pressure regulators are to be distributed as a minimumat.

Land Rig

Rig floor 2 manifolds, each provided with 5 connectionsDerrick deck 1 manifold provided with 3 connectionsNear the substructure 2 manifolds, each provided with 5 connectionsShale shakers 1 manifold provided with 5 connectionsMud pit 1 manifold provided with 5 connectionsMud pumps and engines 1 manifold provided with 5 connections

Platform

Rig floor 2 manifolds with 5 connections eachCellar deck/moonpool 1 manifold with 5 connectionsMonkey board 1 manifold with 3 connectionsCrane box/cage 1 manifold with 3 connectionsShale-shaker area 1 manifold with 5 connectionsMud pit room 1 manifold with 5 connectionsPumps room 1 manifold with 5 connectionsEngine room 1 manifold with 5 connectionsSCR box 1 manifold with 3 connectionsControl room 1 manifold with 3 connections

• The cascade system shall be equipped with bottles arranged in ranks andpositioned as per the ‘Safety and Emergency Plan’ prepared by the DrillingContractor.

• The minimum air reserve available (number of bottles) shall be at least enough toallow 10 people to work for 10hrs in normal breathing conditions withoutrecharging bottles.

• For these it is preferred to have systems, the installation of two compressorslocated so as to allow to access to either one of them for bottle recharging tocater for the direction the wind blows.

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The Compressors shall have the following features:

• Capacity equal to 17cu ft/min (480 l/min)• Maximum charge pressure 3,000psi (208bars)• Filters and air cleaners as per DIN 3188 regulation• Alarm and control system for CO2 high temperature and oil content• Gauges, safety and oil pressure control valves• Double powering: electrical and diesel• Skid and protection structure.

Note: Installation and testing of the cascade system cannot be carried out bydrilling contractor personnel, but only by specialists.

Where previous operations in the area have already ascertained the presence of H2S, it isrecommended to stipulate contracts with contractors for, the supply of equipment, training offield personnel, inspection of equipment efficiency, and an expert assigned to the rig.

10.13. USE OF BREATHING APPARATUS

The 10min Automatic Positive Pressure Escape Breathing Apparatus must be used only toabandon the danger area.

Such apparatus (which each worker must always have at hand ) located by the rig floor,substructure, mud pumps, shale shakers, mud mixing area, engines and mud logging unitmust be worn when the alarm activates.

The 30-45min Self Contained Breathing Apparatus must be worn when working in a pollutedenvironment or when having to enter a polluted closed area. In the latter case their mustalways be two operators in a team.

10.14. ADDITIONAL SAFETY FEATURES

A drilling rig operating in a ‘sour area’ must be provided with the equipment related in theAppendix A.

With reference to items not previously addressed, the following considerations must bemade:

• For land rigs, access to the rig is to be provided with a gate or barrier forbiddingadmittance to personnel not concerned with operations.

• Two wind sleeves or flags, at minimum, must be set up in such a way as toindicate wind direction. They must be visible from the rig and from the emergencysafe area( visible day and night), by placing close to lights.

• The rig must be provided with two or more fans to ventilate rig floor,substructure shale shakers area when wind is absent.

• All circuits and electric engines must be explosion proof.

ARPO




Note: Appendix A shows an optimal land location arrangement. This example,however, is binding when the presence of H2S is ascertained (thereunion areas must be indicated by the Contractor Toolpusher).

10.15. INSPECTION/MAINTENANCE OF DETECTION/PROTECTION SYSTEMS

Periodical inspection and maintenance of the monitoring and individual protection systems isthe responsibility of the Drilling Contractor and of the Mud Logger (as far as the sensors areconcerned). They must be carried out on the basis a maintenance schedule and criteria setforth by the equipment manufacturer/supplier.

Such operations must be planned by the Toolpusher at the beginning of the drilling activity.

A copy of the specific handbooks, reporting testing and checking procedures must beavailable at the rig and at the disposal of the Eni-Agip Drilling and Completion Supervisor.

It is the duty of the Contractor's Toolpusher to make sure that all systems are kept in perfectworking order.

It is the duty of everyone provided with individual safety equipment to keep it clean and verifythat the components are in working order.

The following table provides an inspection and maintenance program indicating the maximumintervals for verifications.

It is the duty of the Eni-Agip Drilling and Completion Supervisor to make sure that inspectionand maintenance are carried out within the limits fixed by the table 10.bC below.

ARPO




DESCRIPTION TYPE OF INSPECTION INTERVAL

Self breathing apparatus (30-45min)

Charge pressure, valve,masks, parts in rubber

15 days

Spare bottles Valves 15 daysCompressor Air filters, working pressure, oil

and fuel levels30 days

Self breathing apparatus(10min.)

Charge pressure, valves,masks, parts in rubber

15 days

Portable meters for H2S andSO2

General conditions 30 days

Phials for H2S Expire date 30 daysPhials for H2S Expire date 30 daysSensor for H2S in the air functionally and adjustment 7 daysAcoustic and light alarmsystem

Functionality 7 days

Means of internalcommunication

Functionality 7 days

Explosion-proof electric torch Functionality 7 days

Table 10.B - Inspection/Maintenance Schedule

ARPO




APPENDIX A - H2S Detection And Danger Areas

CONSTANT H2S DETECTION FOR LAND RIGS

DESCRIPTION QUANTITYEquipment for the constant detection of H2S concentration consisting of:

• Unit with control panel and tool indicator of the H2S concentrationwith range capacity of 0-50ppm and two alarm levels (10ppm -20ppm)

Dependent on rig type

• Sensors with short response time as per market availability Dependent on rig type

Portable detectors to measure H2S in the atmosphere (either manual orelectronic).

3 manual2 electronic

Colorimetric vials for H2S:10 vials package. 1-200ppm 1010 vials package: 50-500ppm 510 vials package: 100-2000ppm 5

Colorimetric vials for SO2:10 vials package: 1-200ppm 510 vials package: 20-200ppm 510 minutes Automatic Positive Pressure Escape BreathingApparatus.

30 for land rig120% of the rig and

supply vessel personnelfor off-shore rig

30-45 mins Self Contained Breathing Apparatus for land rig 15Extra cylinders for Breathing Apparatus for land rig 4530-45 mins Self Contained Breathing Apparatus for off-shore rig 120% of emergency

teamExtra cylinders for Breathing Apparatus for off-shore rig 3 spare bottles per

breathing apparatusAMBU type reanimator 2Battery operated portable explosimeter 2Wind sleeve 2Two tone alarm hooter 2Walkie talkie completed with batteries and battery loader 6Electric lamp (explosion proof type) 6Alarm flashlight 2 red 2 yellowGas garret Train Test Kit or Hatch Test Kit 1 (in sour area)H2S Scavenger for mud 30kg/m3 of mudFan 3

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A.1. Confined Location

BURNPIT

BURNPIT

FLARE STACK(optional)

ALTERNATEROADBARRICADE WITHCAUTION SIGN

WINDSTREAMER

BRIEFINGAREA ANDPROTECTIONCENTER

PIPERACK PIPERACK REMOTE BLOW OUTPREVENTER STATIONAND ACCUMULATOREQUIPMENT

SUB STRUCTUREBASE SUB STRUCTUREBASE

LIGHTHORN

MUD GAS SEPARATORSHALE SHAKER

LIQUID KNOCKOUT(optional)

MUDTANKS MUDTANKS

DEGASSER

CHOKEMANIFOLD

MUD LOGGINGUNIT

MESS HALLOFFICEAND/ORSLEEPINGQUARTERS

MUDHOUBE

PUMPPUMPPUMPRIGPOWERPLANT

RIGFUELWATERTANKWATERTANK

WINDSTREAMER

BRIEFINDAREA ANDPROTECTIONCENTER

BARRICADE WITHCAUTION SIGN

ENTRANCEROAD

FLARE

PREVALING WINDDIRECTION

FLARE

ARPO




A.2. Unconfined Location

SUB STRUCTUREBASE SUB STRUCTUREBASE

HORN LIGHT

WINDSTREAMER


ENTRANCEROAD

WINDSTREAMER


FLARE STACK(optional)

PREVALING WINDDIRECTION


COMPANYHEAD QUARTERS

CONTRACTOR'STOOLPUSHER ANDDRILLING FOREMAN'SOFFICE

CHANGEHOUSE

RIG POWERPLANT


ALTERNATEROAD

REMOTE BLOW OUTPREVENTER STATIONAND ACCUMULATOREQUIPMENT

PIPERACK PIPERACK

MUD LOGGINGUNIT

CATWALK

DOG HOUS

CHOKEMANIFOLD

MUD GAS SEPARATORLIQUID KNOCKOUT(optional)

SHALE SHAKER

MUD TANKSDEGASSER

MIXINGPUMPMUDHOPPER

PUMP PUMP PUMP

MUDHOUSE

WATERTANKS RIG FUELTANK

BURNPIT

BURNPIT

FLARE

FLARE

RESERVEPIT

ARPO




A.3. Typical Land Rig Breathing Apparatus Locations

Rig Floor

Substructure

Bell NippleA-Y-R

S

Derrick Board

S

Workshop

Safety Material

Contractor's

Office

AgipOffice

Mud Logging

UnitA-Y-R

Shaleshakers

Mud PitMud Pump Zone

S

Mud Mixing Area

S = Sensor

A = Alarm ring

Y = Yellow Flashing Light

R = Permanent Red Light

LEGEND

S

= 30' - 45' SCBA.

= 10' SCBA.

= Wind Sleeve

ARPO




A.4. Emergency Form (To Be Filled When An Emergency Occurs On An En-Agip Rig)

EMERGENCY FORM TO BE FILLED WHEN ANEMERGENCY OCCURS ON AN ENI-AGIP RIG

01. HOUR / DAY:

02. WHO IS CALLING: NAME TELEPHONE

03. RIG NAME / LOCATION:

04. HOUR OF ACCIDENT:

05. NATURE OF ACCIDENT: FIRE, EXPLOSION, BLOW-OUT, POLLUTION,

H2S, COLLISION, STABILITY PROBLEMS,UNCONTROLLED FLOATING, COLLAPSE OF

HOISTING EQUIPMENT, RADIOACTIVE LEAKAGE,

ACCIDENT TO A DIVER, MAN AT SEA, OTHER:

06. NUMBER OF PERSONS AT THE RIG:07. NUMBER OF PERSONS WOUNDED:

08. NUMBER OF PERSONS MISSING:

09. DECEASED:

10. EXTENT OF DAMAGE:

11. EVACUATION / RESCUE: YES/NO HOW?

12. ACTIONS TAKEN ON THE RIG:

13. ASSISTANCE REQUIRED:

14. WEATHER CONDITION: WIND : VISIBILITY:

WEATHER: CLOUDS:SEA CONDITION:

CURRENT:

SEA TEMPERATURE:

ENVIRONMENT TEMPERATURE:

15. ACTIONS TAKEN:

16. PARTECIPANTS:

NAME TELEPHONE

NAME TELEPHONE

NAME TELEPHONE

17. OTHER INFORMATION:

ARPO




A.5. Territorial Emergency Report

TERRITORIAL EMERGENCY REPORT

1. Date: Hour:

2. Installation:

3. Nature of the accident: Gas Oil Water

4. Esteemed flow:

5. Blowout esteemed height:

6. H2S indication:

1. Danger area (300 m around the well over 360°)

- H2S concentration:

- SO2 concentration:

around the well over 360°)



2. Health damage risk area (from 300 m to 1000 m

over 360°)



3. Polluted area (over 1000 m around the well,

ARPO




A.6. H2S Drill Report

H2S DRILL REPORTEni-Agip Spv. and Rig Contractor Rep. must be awared

of the Company H2S Procedures

Well .................... RIG name.................. ...................Rig Spt. ...................Mudlogging .................... TDC .................... Mudlogger ...................Present Operation ..........................................................H2S sensor: Sh. shaker Rig Fl. B.O.P. Mud Pit OtherType of test: Weekly alert Emergency Programmed ...................................

Date............. hrs..............(hrs at the start test)

Alarm from Rig Fl after min: ........ H2S ppm .....Alarm from Mudlogging after min : ...... H2S ppm ....

Personnell on Rig Fl n°: .....

Total time wear all the breathing apparatus: min. ......

Total time to put the well in safety condition: min. .....

BOP and Choke Mnfd. H2S Service? yes no

ALARM SET UP:

Sensor:Sh. shakerRig FloorBOPMud pit

1st alarm 2nd alarmDate oflast test

...........

...........

Alarm set up from instructions by: .......... Date: .......Test of sensors:Metod ...............................................

H2S equip. in good condition and corrent location YES NO

STOCKSBarite t. ......... Scavenger t. ........ Kill mud: kg/l ......... Volume mc................................Skill level : Good Sufficent Poor

NOTE:

Test n°... Eni-Agip Spv. ............ Eni-Agip Spt. Eni-Agip Drl. Manager...............

By ..................................................................(name and title of person starting the test)

Present ..... Absent ..... ...........................

Total time for meeting in safety area min: .....

Expiring data fo filters, masks ect.: Expired n° ......

Country ...............Field ..............

Rig ContractorDriller ......................

Alarm set @ ppm ............

Alarm set @ ppm ............

Date of last test ..............

Well sketch

CSG m

T.D. m

O.H.

NOTE: bit depth at H2S drill m

Type ....................... .......................

Safety meeting after test? Yes no

H2S safety equipment all present yes no

ARPO




APPENDIX B - Bibliography

Document: STAP Number

Overpressure Evaluation Manual STAP-P-1-M-6130

Drilling Procedures Manual STAP-P-1-M-6140

eni - well control policy manual

Documents

stripping procedure

soft shutin procedure

property of agip

control methods

primary control

secondary control

control derogation

annulus pressure control