sect 01-02 pwc students

7/25/2019 Sect 01-02 PWC Students

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Schlumberger IPM

PreventativeWell Control

Course

Sections 1 and 2

IPM Well ControlIPM Well Control


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Safety issues.

Fire escapes.

Lunches & Coffee breaks.

Toilets.

Computers and cell phones.

Questions????

Before we get started


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Why the Preventative Well Control Course?

Two main reasons for the PWC Course:

1. The number of well control incidents in IPM has reached an

unacceptable level:

- IPM incident rate: 1/60 (includes all WC incidents, kicks-blowouts).

- Industry average: 1/615 (only includes blowouts).

2. To develop a common culture: because IPM is made up of people

from different backgrounds and companies, there is not a commonculture. It is a good opportunity to bring various well control ideas

together, share experiences and bring everybody to the same page.


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IPM well control training includes 3 elements:

1. Basic introductory module for new hires and fresh outs

(fundamental WC).

2. IWCF regulatory training or equivalent certification as per

country of operations regulations and client requirement.

3. Preventative well control course IPM mandatory.

IPM Well Control Training


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Introduction

IPM standards

The U-tube

Kicks causes, prevention and detection Well control by well design

Well control equipment

Diverters

Shut-in procedures

Course Outline


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Well control in OBM

Gas migration effects

Constant BHP well control

Other methods of well control Ballooning

Well control in workover operations

Course Outline


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Well Control and IPM Standards

Pre-Tests (2 hours) We want to determine your level of understanding ofwell control

40 Questions IPM standards

40 Questions Well control based

Keep answers short and to the point

Answer all questions that you know first

There is one unconventional part of the test:self-assessment - Please write what you think yourscore is at the bottom of the page


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Section 1

Introduction


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Introduction - Section 1

Well control incidents examples, consequencesand costs

Root causes of IPM incidents

The objective of the PWC


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Well Control Incident Dacin

Well GG-617


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IPM Well Control Incidents

Root Causes, examples: Complacency Lack of knowledge and skills of rig personnel

Lack of commitment and leadership

Inadequate work practices and WC preventative training Inadequate Well Design

Lack of training in PWC

Application of standards

Poor contractor & supplier management Inadequate risk management & management of change

process

Lack of communication


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49%17%

17%

17%Well Control

Cementing

Stuck Pipe

Casing & Completions

Distribution of IPM Incidents by type

(2 year period form 99 00, +/- 300 wells)


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(2003, +/- 1400 wells)

15%

9%

7%

4%

3%3%

3% 3%1% 1%

51%

0%Stuck Pipe

Well Control

Hole Conditions

Loss Circulation

Others

Program Error

Wellhead equipment

Cementing Problems

Downhole equipment Failure

Rig contractorWireline

Waiting on equipment


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(2004, +/- 1750 wells)

15%

17%4%

21%

2%

10%2% 3%

23%

3%

Drilling Equipment

Drop tool / String in well

Kick / InfluxLoss Circulation

Rig Contractor

Stuck Pipe

Support Equipment

Tool

Unplanned Cement left in string

Unsuitable Conditions


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(2005, 1984 wells)

30%

21%

13%13%

11%

8%

4%

Stuck PipeLoss/failure equipment

Well Control Incidents

3rd party equipment

Loss of operation activity

Loss Circulation

Others

Sum of % of total NPT (year 2005)

Category


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(2006, XXX wells)

12%

12%11%

10%

8%

8%

8%7%7%

5%

5%

3%

2%

2%

0%

0%Loss of Operation Activity

Stuck Pipe / Tools

Unknown

Loss Circulation

Other

Downhole Equipment Failure

Cementing

Well Control

Hole Problems

Waiting

3rd Party Contractor Equipment

Rig Equipment

Loss / Failure of Equipment

Equipment

Primary Mechanical

Acquisition/Computers

Sum of % of total NPT(year 2006)

Category


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(2006, XXX wells)

20%

17%

13%

13%

8%5%5%4%

3%3%

3%2%

2%2%%%

Well Control

Loss Circulation

Stuck Pipe / Tools

Loss of Operation Activity

Cementing

3rd Party Contractor Equipment

Downhole Equipment Failure

Other

Unknown

Hole Problems

Waiting

Rig Equipment

Equipment

Loss / Failure of Equipment

Primary Mechanical

Acquisition/Computers

Sum of % of total Red Money (2006)

Category


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IPM Well Control History

(1995 December 2006)Year

Reported

Kicks

Reported

Blow Outs

# Wells

Total

Wells /

Kick

Wells /

BlowoutComments

1995 0 0 24 - -

1996 5 0 145 29 -

1997 19 1 536 28 536 Drilling

1998 14 0 507 36 -

1999 4 3 300 75 100 Cem, drlng, rig move

2000 8 6 493 62 82 Cem, drlng, log, trip

2001 14 3 1,595 114 532 B/O on W/Overs

2002 21 2 1,570 75 785 B/O on W/Overs

2003 20 3 1,414 71 471 B/O Operator Error

2004 27 1 1,752 65 1,752 Gas at surface

2005 15 0 1,984 132 -

2006 19 2 2,300 121 1,150

Total 166 21 12,620


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187 well control incidents in187 well control incidents in144 months!!144 months!!

IPM Well Control History

(1995 December 2006)


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A catastrophic well control incidentA catastrophic well control incident

could put IPM out of businesscould put IPM out of business

Former IPM President


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What are we trying to do? Eliminate mistakes which create well control incidents

How are we going to do this? Increase (advance) our understanding of the well

control problems that are occurring and theprocedures that are likely to be used in our operations

Aim to push competence to decide what to do andhow to do it on the rig-floor level

PWC Course Motivation


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What should be our attitude?

We (EVERYBODYEVERYBODY) should be open to having ourunderstanding increased and corrected

We should try to create an atmosphere in this classwhere you can say I do not understand that or Imnot sure I understand that

We should look for simple, practical solutions to Well

Control ZeroZero Well Control IncidentsWell Control Incidents

PWC Course Motivation Cont.


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2 hours

Well Control & Standards Tests


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Section 2

IPM Standards


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Section 2

What are standards

Which standards apply to (preventative) wellcontrol


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Policy A company statement of governing principles

Standard A document detailing a minimum level of excellence or

adequacy to be attained Procedure A document detailing the established way of

conducting an activity

Guideline Document to guide work in order to comply with

policies and standards

SLB Policies and Standards


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Statement of Policy - Operations will be conducted inlegal, ethical, and responsible manner.

Management dedicated to:

Improving quality of operation Ensuring health & safety of staff and others Protect the environment These principles to be held as equal to financial results

Schlumberger Goal: Become the recognized leader in QHSE Make QHSE an integral part of IPM culture

IPMs Adherence to QHSE Policy (1)


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IPM will establish standards, guidelines, and proceduresand communicate to everyone involved in projects.

IPM will operate under policies, standards, guidelines:

First, those of Schlumberger Limited

Second, those of Schlumberger Oilfield Services

Finally, those of IPM (which will take priority if morestringent)

IPM will prepare a bridging document for all work outside

Schlumberger

Key differences to be addressed and documented

IPMs Adherence to QHSE Policy (2)


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A SIMOPS plan is required on all projects where drilling and /or intervention work is proceeding within 30 meters of eachother and / or production operations

Objective is limiting excessive risk imposed by multiple

operations at the same time as opposed to the risk associatedwith the execution of these operations individually

SIMOPS: two or more major operations carried outsimultaneously as any of these activities: production orinjection, live well operations, pigging operations, running or

pulling riser or heavy lifting, skidding rig, hot work, drilling andworkover operations, conductor driving and installation,injection to annulus, repair or c/o Xmas tree or annulus valvesor pumping and flowing through temporary lines

Simultaneous Operations (SIMOPS) (1)IPM-ST-WCI-033


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As a minimum, the SIMOPS plan shall contain the

following sections:

Introduction

Duties and responsibilities

Review / risk analysis of SIMOPS

Safety system

Emergency procedure Technical data

Simultaneous Operations (SIMOPS) (2)IPM-ST-WCI-033


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A Bridging Document is to be prepared during theplanning stage of all IPM Projects, preferably beforefinalizing the Operations Program. The Bridging Documentmust, in all cases be finalized prior to starting any

operations

Objective:1) To reconcile the different standards, practices and/or

procedures that the various players involved in IPMsupervised operation may have, in order to obtainconsistency

Project Bridging Document (1)IPM-ST-WCI-030


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Objective, Cont.:2) To resolve potential differences prior to the start of

operations, particularly when it comes to implementingcertain fundamental procedures where there is room for

interpretation and clarification

Topics Include:- General - Well control- Shallow gas - Directional drilling- H2S - Logging- Daylight ops - Well ops standards and procedures- Exemptions to IPM Standards



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Well Control Related: Well control certification requirements Well control drills: type and frequency BOP configuration: requirement for casing rams

BOP (& related equipment) tests: function, pressure,frequency, test pressures, BOP test sheet

Casing pressure test requirements Leak Off Test (LOT) Kick tolerance while drilling Standard regarding drilling breaks



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Well Control Related: Flow check standard (frequency and duration)

Amount of pressure overbalance to maintain in staticconditions

Pore pressure prediction/detection methods

Review of kick detection equipment (PVT, flow indicators)

Minimum chemical stocks (barite and cement)

Amount of active mud volume and reserve mud volume and

weight SCR frequency



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Well Control Related: Agreement on general well kill methods, pre-recording

of information, standardized well control worksheet andformula

Detailed shut-in procedure Stripping checklist Wellsite individual responsibilities and line of command

during well control operations Surveying standard for vertical wells



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Intention: to comply with the minimum standards

If a standard cannot be complied to:

Obtain exemption in a specific operation, under specialconditions, previous analysis and evaluation / mitigation of the riskinvolved (risk management)Exemptions are alerts to the managersAn exemption request must be submitted in QUESTExemption procedure is detailed in the Standard:

SLB-QHSE-S010, with IPM appendix

What happened if standard cannot be complied to?


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SLB operations are continuously subject to change, implying that

associated risk levels also evolve. It is essential that these changes are

managed in a controlled manner so that risk is always maintained at an

acceptable level

SLB expectations for key business deliverables are defined through

associated management systems, policies, standards and work

instructions

Management of Change and Exemption Standard (1)

SLB-QHSE-S010


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Management of change process: Process to manage significant

changes associated with increasing and decreasing risk levels.

Exemption process: Process to obtain appropriate approval for

deviation from SLB policies and standards for a specific period of time.

Significant change: Any change that introduces new hazards or any

change that causes an increase in the level of the risk that has the

potential to result in an HSE accident or an SQ non-conformance.

Examples of such changes are: environment, equipment, personnel,

process, etc.


SLB-QHSE-S010


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This standard describes what to do when significant change is

introduced following deviation from:

Contractual terms and conditions, work-scope, historical norms,procedures and work instructions using the management of

change process

Policies and standards using the exemption process


SLB-QHSE-S010


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The management of change and exemption processes shall be followed

in order to manage the operational risk and grant and control exemptions

to policies and standards, so that:

Our people, assets and the environment are protected from any

coercion to perform operations beyond standard practices

Risk is adequately managed, following the steps defined in the

HARC standard, as technologies and processes, that are notaddressed by existing documentation, are intentionally or

unintentionally introduced


SLB-QHSE-S010


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All exemption requests should be written in such a way that they apply to

the specific activity requiring the deviation from a policy or a standard

requirement, their use must be limited to the segment or operational unit

and the validity kept to a maximum of 12 months.

In no circumstances should requests be submitted, and in no

circumstances may they be approved, with respect to any action that

may or will lead to non-compliance with applicable laws and regulations,

which shall be adhered to at all times.


SLB-QHSE-S010

f Ch d i S d d ( )


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The management of change and exemption processes shall be followed

to manage operational and commercial risk by ensuring that all

significant changes to design, equipment, operations, modifications and

deviations from policies and standards are justified, approved, recorded

and monitored in a controlled and effective manner and that relevant

parties are identified and advised of changes as needed, including

during personnel handovers.

The sequential procedure to be applied is illustrated in the next slide.


SLB-QHSE-S010

M t f Ch d E ti St d d (8)


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1. Originator identifies the significant change

2. Direct line Manager of Originator set up a risk assessment team

3. Comprehensive risk assessment is performed

4. Risk control plan to lower risk to ALARP is developed (HARC)

5. Approver reviews all the details of the request

6. Originator obtains approval from relevant Approver

7. Upon approval Originator must communicate details of the

Management Of Change (MOC) or exemption to all those involved

8. Activity is performed

9. Originator must close out the MOC or the exemption


SLB-QHSE-S010

M t f Ch d E ti St d d (9)


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If repeated requests are being made for the same exemption, thenthe

case should be reverted to the appropriate owner of the corresponding

policy / standard for a possible revision of the associated document

All exemption shall be logged into QUEST at originating location; if not

feasible request shall be logged into QUEST by the QHSE functionat the

appropriate level


SLB-QHSE-S010

What Happens When Things Change?


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Risk Analysis(Prevention & Mitigation to

ALARP)

Original Workscope

What Happens When Things Change?

Well proposal

Basis of design

Operations

program

End of well

report

New Hazards and Risks ?

Modified Workscope

Well proposal

Basis of design

Operations

program

End of well

report

Management of Change Process


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Management of Change ProcessIdentify new hazards

and risks resulting

from the change

Analyze risks

Identify Prevention& Mitigation Measures

to reduce risk

to ALARP

-25/5MC-20/4MC-15/3MC-10/2MC-5/1MC

-20/5C-16/4C-12/3C-8/2C-4/1C

-15/5M-12/4M-9/3M-6/2M-3/1M

-10/5S-8/4S-6/3S-4/2S-2/1S

-5/5L-4/4L-3/3L-2/2L-1/1L

Sev

erity

Likelihood

Acknowledgethe

change

Modify

Program or

Procedure

Communicate

& Proceed

Obtain approval

from initial

program/procedure

approver


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Section 2

IPM Standards related to Well Control

Group discussion


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Standards Presentations

Review the IPM standards related to well control andReview the IPM standards related to well control andbriefly explain why they are important and how they applybriefly explain why they are important and how they applyto the operationsto the operations

Ki k D t ti E i t (1/2)


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Minimum standards for kick detection equipment:

Pit Volume Totalizer (Pit Volume Totalizer (PVTPVT) System.) System.

Drilling fluid return indicator (Delta Flow Meter).Drilling fluid return indicator (Delta Flow Meter).

Trip Tank Indicator.Trip Tank Indicator.

System requirements:

Electronic or analog pit level indicator to measure mud tank levels.

Display for key information.

Visual and audible warnings.

Measurements by:

Mud pit probes (potentiometric sensors) in the mud tanks.

Mud flow return sensor (paddle) in the flowline.

Kick Detection Equipment (1/2)IPM-ST-WCI-003

Ki k D t ti E i t (2/2)


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Display visible to the Driller, show the following:

Trip tank volume.

Mud return.

Individual volume of all pits.

Summing of volumes of selected.

The gain/loss measurement reset automatically to zero by a pushbutton. The gain/loss and mud return measurements equipped withvisual and audible alarm.

The drilling contractor is responsible for maintaining this equipment ingood working order at all times.

Kick Detection Equipment (2/2)IPM-ST-WCI-003

Well Control Equipment Testing Requirem


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The BOPs and related equipment will be tested regularly.The BOPs and related equipment will be tested regularly.

Equipment in safe and reliable condition that will withstand maximum

anticipated wellhead pressure.

Frequency: Every 14 days or during the first trip after the 14-day

interval with a maximum interval of 21 days.

Low pressure test (200 to 300 psi) for 5 min. and high pressure testswill be conducted for a minimum of 10 min.

The diverter system will be function tested on installation.

Calibration: trip tank, flow meters, and critical sensors/monitors should

be accurately calibrated on a regular basis.

Well Control Equipment Testing Requirem.IPM-ST-WCI-004

BOP Stack and Diverter Minimum


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Provide sufficient BOP integrity and operational flexibility toaccommodate all anticipated well control situations.

Working Pressure:

Exploration wells: full evacuation of the well to gas (dry gas, 0.1 psi/ft).

Development wells: maximum shut-in tubing pressure (analysis of PVTof fluid, reservoir fluid composition, injection or stimulation).

Equipment Specification:

BOP: in accordance with, or exceed API RP 53.

H2S areas: NACE requirements. Accumulator and closing times: API Spec 16D and API RP 53.

Diverter: API RP 64.

BOP Stack and Diverter MinimumIPM-ST-WCI-005

Well Control Certification


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All IPM supervisory staff involved in well operations shall have a

valid and recognized well control certificate, and have successfully

completed Preventative Well Control (PWC) training.

All other IPM project technical staff complete the WCF.

The recognized well control certificates are: IWCF, IADC-WellCAP,

PITS, GOST.

If a region or country has local regulations requiring certification other

than IWCF (or equivalent), all IPM operations will comply with localregulations.

Well Control CertificationIPM-ST-WCI-006

Consensus of Well Control Procedures


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To avoid conflict and confusion during well control operation.

Prior to start well operations, agreement with the Operator and the

Drilling Contractor in: well control procedures, formulae, systems of

units, conversion factors, capacities, and kick sheets.

Agreement in Bridging Document and Well Control Briefing

Document.

Well control procedures available to key office and wellsite personnel.

Shut in (or divert) procedures will be posted at the Drillers position.

IPM personnel must be conversant with: Well Control Manual, Project

Bridging and Well Control Briefing Document.

Consensus of Well Control ProceduresIPM-ST-WCI-007

Well Control Drills


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Repetitive Drills:

Increase the awareness of kick recognition.

Familiarize rig-site personnel with the operation of well control

equipment, the actions to be taken and their respective functions.

Well control drills will be held, as a minimum, on a weekly basis.

Drill will include special procedures, different from those of the Drilling

Contractor.

The Well Site Supervisor will ensure that the drills are recorded in thedaily drilling reports.

Well Control DrillsIPM-ST-WCI-008

Casing Liner and Tubing Pressure Testing (1/2)


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All casing strings and liners (including lap areas and seals) shall bepressure tested prior to:

Drilling out the shoe track.

Perforating.

Commencing completion operations.

Maximum Test Pressure: not exceed the rated pressure of thewellhead, BOP, or 80% of the minimum internal yield of the weakest

segment of the casing string.

Minimum Test Pressure: the effective pressure during the test at anypoint shall be at least 110% of the maximum pressure which thatpoint shall experience during the lifetime of the well or tubular in

question (without exceeding the maximum test pressure).

Casing, Liner and Tubing Pressure Testing (1/2)

IPM-ST-WCI-009

Casing Liner and Tubing Pressure Testing (2/2)


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Liner-laps: tested to a minimum of the formation leak-off pressure at

the casing shoe.

Production/Test/Injection Tubing: as a minimum, the test pressure

shall give an internal pressure at the lower section of tubing or packer

assembly equivalent to 110% of the pressure load from the shut-in

tubing pressure and the produced or injection fluid.

Repeat pressure tests if mechanical integrity is in doubt (long rotating

hours, high dogleg severity, or corrosion).

Pressure Test Validity: pressure declines no more than 1% over a

minimum 15 minute shut in period.

Casing, Liner and Tubing Pressure Testing (2/2)

IPM-ST-WCI-009

Minimum Chemical Stocks


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Mud weighting material and cement, to handle unexpected wellcontrol situations.

The minimum stock levels are:

Weighting material: to raise the entire mud circulating volume by 120

kg/m3

(1 ppg ), or to the leak off, whichever is the lesser. Cement: 120 meters (400 feet) open hole plug in the current hole size

with a 100% contingency (offshore or remote locations).

If the minimum stock is unavailable, the WSS is directed to cease

drilling operations until there is sufficient stock on location tocontinue.

Minimum Chemical StocksIPM-ST-WCI-010


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Barriers (1/2)


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Barrier: any impervious material or device that can be demonstratedto temporarily or permanently prevent the flow of wellbore andreservoir fluids.

After setting the surface casing string, wells shall have two or moredissimilar tested and impermeable barriers at all times.

Barrier Testing and Integrity:

A barrier is acceptable when it has been tested in the direction of flowand demonstrated to hold pressure to the maximum potentialoperating pressure with zero leakage.

Pressure tests shall be for 15 minutes for positive pressure tests and30 minutes for inflow tests.

Barriers (1/2)IPM-ST-WCI-012

Barriers (2/2)


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Barriers for Open Hole Wireline:

Normal operations: barriers are the drilling or completion fluids and

the rig BOP.

Losses or gains: the fluid cannot be considered a barrier. Wireline

surface pressure equipment shall be considered. On failure of a barrier the WSS shall initiate immediate measures to

secure the integrity of the well and restore or replace the failed

barrier. Other activities should cease unless doing so increases therisk of an incident.

Barriers (2/2)IPM-ST-WCI-012


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Well Control Method


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IPM use industry recognized methods (Drillers, W&W andVolumetric).

The Drillers method is preferred when the bit is on bottom.

The combined Volumetric / Stripping method is preferred when the

bit is off bottom, followed by the Drillers method once the bit is onbottom and / or below the influx.

All IPM personnel responsible for well operation must be conversantwith the recognized industry accepted well control methods as wellas with the non-conventional methods used in specific situations.

IPM-ST-WCI-016

Kick Detection


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Any influx of formation fluids will be detected as quickly as possibleby:

Performing flow checks of all drilling breaks.

Monitoring pit volumes.

Training personnel in kick detection.

Objective: to minimize the reaction time, size of influx, and severity of

well control operations.

All rig crews must understand the importance of early recognition

of a kick. Shut-in procedures or diverter procedures, must be posted near the

drillers controls in English and in the local language.

IPM-ST-WCI-017

Kick Prevention (1/2)


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Primary well control: fluid density >formation pressure.

Primary well control is to be maintained at all times.

Minimum overbalance: of 200 psi, or 50 psi with the riser removed(offshore operations).

Consideration to pump heavy pill prior to POOH. Run swab and surgecalculations.

Periods with no pipe in the hole must be reduced to a minimum.

( )IPM-ST-WCI-018

Kick Prevention (2/2)


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The Driller or designated relief must ensure that: Hole full at all times.

Use trip tanktrip tankwhen tripping.

Trip sheetTrip sheet, filled out on every trip (deviations must be investigated).

Discrepancies investigated by a flow check. Close BOPs if flowcheck is inconclusive.

Whilst POOH flow checks are to be performed:

On bottom.

Bit at the shoe.

BHA is about to enter the BOP (prior to pulling first drill collar). Horizontal wells: bit out of the horizontal section.

Flow check for a longer period when a coring string is at casingshoe.

IPM-ST-WCI-018

Constant Bottom Hole Pressure


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Constant bottom hole pressure in excess of the formationpressure will be maintained, even if theeven if the MAASPMAASP has to behas to be

exceeded prior to the influx reaching open hole weakestexceeded prior to the influx reaching open hole weakest

point.point.

Objective: to prevent any further influx of formation fluids into thewellbore.

The automatic MAASP control feature is kept switched OFF, that is,there will be no automatic choke pressure limitation to MAASP.

IPM-ST-WCI-019

Reporting of Well Control Events


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All well control events will be reported using the IPM WCI Reportusing the template in Quest.

Objective:

To gather historical information.

Report outlining the root causes. Implementation of remedial actions.

Kick: unplanned but controlled flow of formation fluids into thewell bore requiring the closure of BOPs.

Planned Kicks: intentional underbalanced drilling or in setting

upper protective casing(s) in deepwater operations where naturalflows and weak formations necessitate drilling to the extremelimits of kick tolerance.

IPM-ST-WCI-020

Shallow Gas Risk Assessment and Contingencies


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Shallow gas: any gas accumulation encountered during drillingat a depth above the casing setting point of the surface casing.

A shallow gas risk assessment will be made for all well

locations.

In all cases there will be a contingency plan to cover a shallowgas flow.

Consideration shall be given to set the surface casing as shallow

as will allow for well shut in without broaching to surface.

If there is any indication of the presence of shallow gas, gaswill be assumed to be present and the well surface location

will be moved.

IPM-ST-WCI-021

WC while Running and Cementing Casing (1/2)


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Maintenance of Fluid Column: Sufficient fluid height in both the casing and the annulus.

Monitor pit volumes and returns.

Check volumes to fill the casing. Top up the casing every 5 joints.

Run surge calculations.

Primary well control displacing cement and spacers. Monitor pit levels during cementing operations for gains and losses.

Monitor cemented annulus until surface samples are hard.

Maintenance of Barriers

Two non-return valves: running casing into a hydrocarbon-bearing zone.

Automatic-fill float equipment is to be tripped closed.

No differential or automatic fill-float equip. through hydrocarbon zones.

Slotted liner / Screens: contingency plan for well flowing.

IPM-ST-WCI-022

WC while Running and Cementing Casing (2/2)


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Casing Rams Annular preventer: if no run through hydrocarbon bearing formation.

Change upper rams to casing rams: when run through potentialhydrocarbon bearing formation.

Liner run through section with potential hydrocarbon bearing

formations: no need to change rams.

Suitable crossover from the casing threads to the drill pipe threads ismade up to the IBOP and is readily available on the rig floor.

IPM-ST-WCI-022


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Well Control Briefing


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Well Control Briefing is required, before WS personnel assumeresponsibilities.

Objective: to ensure clear understanding of project objectivesrelating to well control.

Specific project Well Control Briefing document: including, e.g.project well control exemptions, shallow gas, kill procedures, lostcirculation zones, abnormal pressure, local tectonics, rig well controlequipment and all other pertinent project information required in theperformance of their well site responsibilities.

Document continuously updated throughout the execution phase.

Re-certification every year, when the document is changed and/orprior to assuming well site responsibilities at a new project.

IPM-ST-WCI-028

Gas Detection Equipment (1/2)


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Minimum Gas Detection Equipment Specification: gas detection andalarm for monitoring of combustible gases and H2S. Visible and audiblealarms. Minimum detection points shall be as follows:

Two portable electronic gas detectors for: oxygen, combustible gases

and H2S.

IPM-ST-WCI-031

5 (rig floor, shaker, cellar deck, mud

tank room, living quarters air intake)

3 (bell nipple, shaker, mud

tank room)

Offshore &

inland water rig

3 (rig floor, shaker & cellar deck)2 (bell nipple & shaker)Land rig

H2SCombustible GasRig Type

Gas Detection Equipment (2/2)


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Gas detector sensors setting: Oxygen Deficiency 19.5%.

H2S Concentration 10 parts per million by volume (ppm).

Lower Explosive Level L.E.L.

Visual low and high level alarms, activate at 10 and 20 ppm

respectively.

High level alarms: activate an audible evacuation alarm.

Equipment calibrated and tested as per manufacturer.

Alarms should be functionally tested at least once daily.

IPM-ST-WCI-031

Contingency Stripping Procedure


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Stripping: movement of tubular in and out of a pressured wellbore. Ram-to-Ram emergency stripping:

Surface stack.

Both rams are solid block of the same size as the pipe.

There is at least one safety ram and a shear ram installed below thestripping rams.

Casing pressure is below 1,000 psi

Annular emergency stripping: casing pressure is below 1,000 psi.Floating rigs, heave below 5 ft with pitch/roll below 1 degree.

Stripping speed: below 2 ft/sec at all times. Requisites: stripping worksheet and pre-job safety meeting.

IPM-PR-WCI-002

Summary


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Standards and guidelines are reviewed periodically. File exemptions, may help to change standards and procedures.

Can be downloaded from InTouch:

http://intouchsupport.com/intouch/methodinvokerpage.cfm?metho

d=iteview&caseid=3271495


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End of sections 1 & 2

sect 01-02 pwc students

Documents