Well Control Manual

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BP EXPLORATION

Text originated by BP Drilling Department

Manual produced by ODL Publications, Aberdeen, Tel (01224) 637171

Introduction and

How to Use

Volume 1

Procedures and Guidelines

Volume 2

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March 1995

WELCOME

Ladies and Gentlemen:

Following is the Second Edition of the “BP Well Control Manual” first issued in 1987. When issued it was expected to be a living document, accounting for changes in technology and experience, it still is. Now, eight years later, horizontal and extended reach wells, coil tubing drilling and under balance drilling have or will become part of our kit for improved profitability.

Our objective with this Second Edition is to bring three changes to the operating groups:

1) Issue the manual in an electronic version as a pilot which may lead to collecting all of the manuals on a server or CD-ROM.

2) Make available Excel based well control worksheets which have been incorporated into the manual.

3) Modify parts of Volume I Chapters 1 and 6 for high angle and horizontal well operations.

In a separate file we have issued the “HTHP Well Control Manual”. Future updates will tie this manual with the “BP Well Control Manual”.

Publication of the manual in electronic format should make the abundance of information in it more accessible to you. A powerful search capability and “hot button” references are part of the software package we have selected. Software used is compatible with Macintosh, MS-DOS and DEC hardware platforms making it accessible to BP and our contractors when needed. Electronic publishing makes modifications easier and we solicit your suggestions for correction, clarification, change or addition to the manual. If we have not managed to make the resource more useful and clear to you we have failed our objective. Your views on how well we have done are important.

To open and use the manual please read the section below. While use of the electronic version of the manual is encouraged there is still the option of printing a hard copy of the manual. Hard copies can still be obtained from ODL in Aberdeen at a cost for printing and shipping.

Originally this manual was not issued as “policy”. In the October 1994 Drilling Managers Meeting this and two other documents, the “Drilling Policy Manual” and “Casing Design Manual”, were designated as the three core policy documents covering our operations. Every effort has been made in this edition to tie to the other two documents.

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March 1995

This manual has been converted into Adobe Acrobat software and is a ‘read only’ version, ie you cannot make any changes to text or figures, you can copy the text and figures and paste them in to another application.

Navigating through the Manual

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Clicking the mouse on the `Main Contents' button at the bottom of this page will take you to the Well Control Manual overall contents list, ie Volume 1 or 2. For additional help use the Acrobat Help files.

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Press the mouse button on the section you require to read, and you will be zoomed into the section, press it again and it will scroll through that section, at the end of the section it will reset to the beginning of the section.

Excel Worksheets

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HOW TO USE

Manual

Volume 1 – Contents

Nomenclature

Abbreviations

1 PREPARATION

Section

Page

1.1 INSTRUMENTATION AND CONTROL

1-1

1.2 MANPOWER ORGANISATION

1-9

1.3 DRILLS AND SLOW CIRCULATING RATES

1-15

1.4 USE OF THE MUD SYSTEM

1-27

1.5 KICK TOLERANCE

1-35

2 THE PREVENTION OF A KICK

Section

2.1 CORRECT TRIPPING PROCEDURES

2-1

2.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE

2-9

2.3 CONTROL LOST CIRCULATION

2-17

3 WARNING SIGNS OF A KICK

Paragraph

1 GENERAL

3-2

2 DRILLING BREAK

3-2

3 INCREASED RETURNS FLOWRATE

3-2

4 PIT GAIN

3-3

5 HOLE NOT TAKING CORRECT VOLUME DURING

A TRIP

3-4

6 CHANGE IN PROPERTIES OF RETURNED MUD

7 INCREASE IN HOOKLOAD

3-6

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March 1995

4 ACTION ON DETECTING AN INFLUX

Section

Page

4.1 SHALLOW GAS PROCEDURE

4-1

4.2 SHUT-IN PROCEDURE

4-9

4.3 DURING SHUT-IN PERIOD

4-17

5 WELL KILL DECISION ANALYSIS

Paragraph

1 GENERAL

5-2

2 PIPE ON BOTTOM

5-2

3 PIPE OFF BOTTOM – (Drillpipe in the Stack)

5-2

4 PIPE OFF BOTTOM – (Drillcollar in the Stack)

5-5

5 NO PIPE IN THE HOLE

5-5

6 WHILE RUNNING CASING OR LINER

5-7

7 UNDERGROUND BLOWOUT

5-9

6 WELL KILL TECHNIQUES

Section

6.1 STANDARD TECHNIQUES

6-1

–

Wait and Weight Method

6-2

–

Driller’s Method

6-3

6.2 SPECIAL TECHNIQUES

6-31

1. Volumetric Method

6-33

2. Stripping

6-47

3. Bullheading

6-67

4. Snubbing

6-75

5. Baryte Plugs

6-84

6. Emergency Procedure

6-93

6.3 COMPLICATIONS

6-97

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March 1995

NOMENCLATURE

SYMBOL

DESCRIPTION

UNIT

A

Cross sectional area

in.

2

a

Constant

–

A

_n

Total nozzle area

in.

2

b

Constant

–

c

Constant

–

C

Annular capacity

bbl/m

C

_p

Pipe capacity

bbl/m

C

_a

Cuttings concentration

%

CL

Clinging constant

–

CR

Closing ratio

–

D

lb

F

_sh

Shale formation factor

–

FPG

Formation Pressure Gradient

SG

g

Gravity acceleration

–

G

Pressure gradient

psi/ft

psi/m

SG

G

_i

Influx gradient

psi/ft

H

Height

m

H

_i

Height of influx

m

H

_p

Height of plug

m

ITT

Interval Transit Time

µ

sec/m

K

Bulk modulus of elasticity

L

Length

m

λ

Rotary exponent

–

MR

Migration rate

m/hr

M

Matrix stress

psi

m

Threshold bit weight

lb

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March 1995

SYMBOL

DESCRIPTION

UNIT

N

Rotary speed

rpm

OPG

Overburden Pressure Gradient

SG

P

Pressure

psi/SG

(The units of subsurface pressure

may be either psi or SG)

∆

P

Adjustment pressure

psi

P

_a

Annulus pressure

Maximum allowable pressure

at the openhole weak point

psi/SG

P

_oc

Wide open choke pressure

psi

P

_p

Pore pressure

psi/SG

P

_scr

Slow circulating rate pressure

psi

PV

Plastic Viscosity

cP

Q

Flowrate

gal/min

Q

_mud

Mud flowrate

gal/min

Q

_gas

Gas flowrate

gal/min

Re

Reynolds number

–

R

Resistivity

ohm-m

Rw

Resistivity of water

ohm-m

ROP

Rate of Penetration

m/hr

Shale factor

meq/100g

S

Overburden pressure

psi

S

_g

Gas saturation

Fractional

S

_w

Water saturation

Fractional

t

Time

seconds

min

TR

Transport Ratio

–

T

Temperature

degrees

C, F, R

TD

Total Depth

m

TVD

True Vertical Depth

m

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March 1995

SYMBOL

DESCRIPTION

UNIT

V

Volume

bbl

cc

ml

l

v

Velocity

m/min

m/s

v

_mud

Mud velocity

m/min

v

_p

Average pipe running speed

m/min

v

_s

Slip velocity

m/min

W

Weight

gm

kg

lb

w

Weight

lb/ft

lb/bbl

SG

w

Weight of pipe

lb/ft

w

_b

Baryte required for weighting up

lb/bbl

w

_cut

Average cuttings weight

SG

WOB

Weight on Bit

lb

x

Offset

( )

YP

Yield Point

lb/100ft

2

Z

Compressibility factor

–

µ

Viscosity

cP

ν

Poissons’s Ratio

–

σ

’1

Maximum effective principle stress psi/SG

σ

’t

Tectonic stress

psi/SG

Ø

Porosity

Fractional

Ø600

Fann reading

lb/100ft

2

β

Tectonic stress coefficient

–

ρ

Density

SG

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March 1995

ABBREVIATIONS

API RP

American Petroleum Institute Recommended Practice

BHA

Bottomhole Assembly

BOP

Blowout Preventer

BRT

Below Rotary Table

DWT

Dead Weight Tester

ECD

Equivalent Circulating Density

EMW

Equivalent Mud Weight

H

₂

S

Hydrogen Sulphide

IADC

International Association of Drilling Contractors

ID

Internal Diameter

KTOL

Kick Tolerance

LCM

Lost Circulation Material

LMRP

Lower Marine Riser Package

LO

Leak off

MAASP

Maximum Allowable Annular Surface Pressure

OBM

Oil Base Mud

OD

Outside Diameter

PMS

Preventive Maintenance System

PV

Plastic Viscosity

ROP

Rate of Penetration

SCR

Slow Circulating Rate

SG

Specific Gravity

SPM

Strokes per Minute

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March 1995

1 PREPARATION

Section

Page

1.1 INSTRUMENTATION AND CONTROL

1-1

1.2 MANPOWER ORGANISATION

1-9

1.3 DRILLS AND SLOW CIRCULATING RATES

1-15

1.4 USE OF THE MUD SYSTEM

1-27

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1-1

March 1995

1.1 INSTRUMENTATION AND CONTROL

Paragraph

Page

1 General 1-2 2 Pressure Gauges 1-2 3 Pump Control 1-4 4 Fluid Measurement 1-6

Illustrations

1.1 Suggested Instrumentation for a Floating Rig 1-3

1.2 Suggested Instrumentation for a Fixed Installation 1-5

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1-2

March 1995

1 General

It is essential that an appropriate level of control equipment is provided on every rig in order that a well that is under pressure can be accurately monitored.

In general, during a well control incident, there is a necessity for more accurate instrumentation than under conditions encountered during routine drilling.

The level of instrumentation on every rig therefore must be evaluated in order to assess its␣suitability for well control purposes. This evaluation should ideally be carried out in␣conjunction with the pre contract rig audit and any deficiencies made good prior to contract␣award.

The purpose of this section is to highlight the important aspects of instrumentation and control and to recommend a standard level of equipment for all rig types.

The level of instrumentation that is recommended will ensure that a suitable level of control is afforded during unusually critical operations, and that adequate back-up is provided. Therefore, much of this equipment would not be necessary in routine circumstances. However equipment failure is most likely when the equipment is highly stressed. It is in these situations that serious incidents can develop if a suitable level of back-up instrumentation and control equipment is not to hand.

2 Pressure Gauges

When a well is under pressure it is important that accurate pressure measurements can be made. Each rig will normally be equipped with gauges to read standpipe pressure and annulus pressure. The gauges that are fitted to the choke panel and at the driller’s console are often the only gauges available for well control purposes.

Although the standpipe and choke manifold will generally be fitted with ‘Cameron’ gauges, these are considered to be so inaccurate as to have little application to well control. All of these gauges will have a fullscale deflection that is at least equal to the working pressure rating of the equipment. In all cases, this means that it will be necessary to install gauges of lower rating in order that relatively low pressures can be accurately recorded. This will be especially important with high pressure equipment.

It is also important that suitable pressure gauges are installed at the choke manifold in case the well has to be controlled from this position. This will apply to land rigs which may be equipped only with manual chokes and the majority of rigs that are equipped with both manual and remote operated chokes.

Accurate readout of pump pressure and choke pressure is, in the majority of cases, all that is required. However an extra pressure reading is required on a floating rig in order that the wellhead pressure can be monitored through the kill line.

In order to be able to install additional pressure gauges it may be necessary to fabricate manifolds and install high pressure instrument hose between the choke panel and the standpipe/choke manifold. All this equipment must be rated to the working pressure of the␣equipment.

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March 1995

Figure 1.1 Suggested Instrumentation for a Floating Rig

SWACO D K C D K C D – DRILL PIPE K – KILL LINE C – CHOKE LINE

– 1/4in NEEDLE VALVES

– CHECK VALVE/HYDRAULIC FLUID INLET

WEOX02.001 FROM BOP FLOWLINE POORBOY DEGASSER CHOKE LINE BUFFER TANK MANUAL CHOKES REMOTELY OPERATED CHOKE KILL LINE OVERBOARD LINE DRAIN PUMP OUTPUT MONITOR CAMERON GAUGE TRANSDUCER 1/4in NEEDLE VALVE CHECK VALVE HYDRAULIC FLUID INLET CAMERON GAUGE STANDPIPE 2 STANDPIPE MANIFOLD CHOKE PANEL CHOKE MANIFOLD STANDPIPE 1

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1-4

March 1995

So in general:

• There must be gauges available to read choke pressure, standpipe pressure and kill line static pressure in the case of a floating rig.

• The above gauges must be readable from the manifold if manual chokes are fitted to the manifold.

• It must be possible to easily install and remove low range pressure gauges at the choke panel and at the choke manifold.

Suggested pressure recording systems for a floating rig and a fixed installation are shown in Figures 1.1 and 1.2. The proposed systems can also be used for measuring slow circulating rate pressures (SCRs).

The following points should be noted from the proposed systems:

• A good selection of gauges should be available. Gauges should be calibrated on a regular basis with a Dead Weight Tester. It is suggested that the gauges are checked at each BOP Test and at this stage the pressure monitors in the mud logging unit should be checked against the rig equipment.

• It must be easy to change the gauges.

• A hydraulic fluid hand pump should be available to purge the lines at suitable points as shown.

• Consideration should be given to completely isolating the supplementary pressure monitoring system from that originally fitted to the rig. This would ensure that the original system was closed and hence in no way susceptible to leaking needle valves or misuse of the supplementary system.

• Sensitive low pressure rated gauges should be removed from the system unless required. The piping and manifolding should be permanently installed. It would be a good idea to fabricate a cover for the manifolding at the choke manifold and choke panel.

• The gauges that are used to measure the slow circulating rate pressures should be used to monitor well pressures in the event a kick is taken.

• A stroke counter, similar to the battery operated ‘Swaco’ unit, is recommended for remote installation at the choke manifold. It should be removed when not required. A suitably isolated terminal should be located at a convenient point at the choke manifold, in order that the signal from the limit switches on the pumps can be transmitted to the counter.

3 Pump Control

It is desirable that the remote control of the pump used to kill a well that is under pressure is located reasonably close to the choke operator.

In most cases the rig pumps will be used. Generally, the Driller will control these pumps from a position that is close to the choke panel. Most choke panels contain a meter that displays the cumulative output of the pump. Therefore, in the majority of cases, if the well is controlled with a remote operated choke, the man on the pump will be able to co-ordinate with the choke operator.

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March 1995

Figure 1.2 Suggested Instrumentation for a Fixed Installation

D C D C SWACO D C – CHOKE LINE D – DRILL PIPE

– 1/4in NEEDLE VALVES

– CHECK VALVE/HYDRAULIC FLUID INLET

WEOX02.002 TO STANDPIPE TO DEGASSER TO DEGASSER TO BURN PIT TO BURN PIT TRANSDUCER CAMERON GAUGE REMOTELY OPERATED CHOKE FROM BOP 1/4in HYDRAULIC FLUID FILLED HIGH PRESSURE HOSE

CHOKE PRESSURE GAUGE TO PUMP/ CHOKE PANEL CHOKE TO BURN PIT STANDPIPE MANIFOLD CHOKE PANEL CHOKE MANIFOLD TO STANDPIPE

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1-6

March 1995

However, if the choke manifold contains manual chokes, the choke operator may be some considerable distance from the man on the pump and a monitor of the pump output. In such cases, it is recommended that a remote pump output meter is positioned at the choke manifold. This will be especially important on land rigs which may be equipped only with manual chokes and where often the choke manifold is located at some distance from the rig floor. A further complication may arise if a kill pump or cement pump is used during a well control operation. It may become necessary to use these pumps on any rig, but the use of a relatively small displacement pump will be standard well control procedure on a floating rig that is drilling in deep water. Therefore, on a floating rig, it is desirable that it is possible to control and monitor the kill/cement pump from the rig floor.

4 Fluid Measurement

During stripping operations, as well as during a volumetric kill, it is important to be␣able to accurately measure small volumes of fluid bled from, or pumped into the␣well.

API RP 53 recommends that ‘a trip tank or other method of accurately measuring the drilling fluid bled off, leaked from, or pumped into a well within an accuracy of half a barrel is␣required’.

Most rigs will not have suitable equipment to do this.

It is usually assumed that the choke manifold lined up across a manual choke to the trip tank␣is a suitable fluid measurement system. However , in most cases this will not be a satisfactory arrangement because of the relatively large volume in the line between the choke and the tank.

In general, there is a requirement for a line from the well, terminating at a manual choke positioned directly above a measuring cylinder, such as the trip tank (hydraulically activated chokes are not suitable for this application). However a bleed line from the well to the mixing tanks on the cement/kill pump may be sufficient.

The most satisfactory arrangement is to use a strip tank as shown in Figure 1.3. This tank would typically have a 3 to 4 bbl capacity so that very small volumes of fluid can be measured. After bleeding into the strip tank, the tank contents can be emptied into the trip tank where the total volume of mud bled from the well, together with the mud leaked past the preventers, can be measured.

Although it is not ideal, it may be sufficient to use a Lo-Torq valve instead of a␣manual choke to bleed fluid to the tank. However, during a long operation this is likely to wash out and so provision should be made to easily and quickly replace the valve.

It is not recommended to bleed mud into a measuring tank that is situated in a confined area when there is a possibility that gas is entrained in the mud.

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1-7 March 1995 1-7/8 FROM CHOKE MANIFOLD/BOP 3in PIPE PRESSURE GAUGE MANUAL CHOKE STRIP TANK (3 – 4bbl capacity) LARGE ID DRAIN LEVEL INDICATOR TRIP TANK FLOWLINE RETURNS WORKING PLATFORM WEOX02.003

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1-9 March 1995

1.2 MANPOWER ORGANISATION

Paragraph

Page

1 General 1-10 2 Individual Responsibilities 1-10 3 Communication 1-12

Illustrations

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1-10

March 1995

1 General

This section is intended to provide a guideline for the allocation of individual responsibilities during a well control incident. It is Company policy that a well control contingency plan should include the allocation of individual responsibilities.

The contingency plan should be drawn up in conjunction with the drilling contractor and should be regularly reassessed. Well control drills provide an opportunity to assess the effectiveness of the contingency plan and to identify and make good any inadequacies.

2 Individual Responsibilities

The well control contingency plan must allocate the responsibilities of all those concerned in the operation. Circumstances at the rigsite may dictate that these responsibilities be modified in the event of an incident; however, the following can be used as guidelines for the allocation of responsibilities in the event of a well control incident:

(a) The Company Representative

• Once the well has been shut-in and is being correctly monitored, to organise a pre-kill meeting for all those involved in the supervision of the well control operation. • To provide specific well control procedures, using the contingency plan as a

guideline.

• To monitor and supervise the implementation of these procedures.

• To be present on the rig floor at the start of the kill operation. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation.

• To maintain communication with the Operations base.

• The Company Representative has the right to assume complete control of the work required to regain control of the well.

• To assign the responsibility of keeping a diary of events. (b) The Company Drilling Engineer

• Will provide technical back-up to the Company Representative. • To keep a diary of events.

(c) The Senior Contractor Representative

• Has the overall responsibility for all actions taken on the rig.

• Has the responsibility for supervising the contractor staff that are not directly involved in the well control operation.

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March 1995

• However, in the event that the well gets out of control, the Company Representative has the right to assume complete control and supervise the work required to regain full control of the well. (This entitlement is a standard condition of Company drilling contracts.)

(d) The Contractor Toolpusher

• Has overall responsibility for the implementation of the well control operation. • Has the responsibility for ensuring that the driller and the drill crew are correctly

deployed during the well control operation.

• Must be present at the rig floor during the start of the kill operation. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation.

• Has the responsibility for briefing the off duty drill crew prior to starting a new␣shift. (e) The Driller

• Has the responsibility for the initial detection of the kick and closing in the well. • Has the responsibility for supervising the drill crew during the well control operation. (f) The Mud Engineer

• Has continuous responsibility for monitoring the mud system and the conditioning of the mud.

It may be prudent to send an extra Mud Engineer to the rig in the event of a well control incident to ensure constant supervision of the mud system.

(g) The Cementing Engineer

• Will ensure that the cement unit is ready for operation at any time.

• Will operate the cement unit at the discretion of the Company Representative. (h) The Subsea Engineer (where appropriate)

• Should be available for consultation at all times during the well control operation. • Has the responsibility for checking all the BOP equipment during the operation. (j) The Mud Logging Engineers

• Have the responsibility for continuously monitoring the circulating system during the well control operation.

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March 1995

3 Communication

One of the Company Representative’s responsibilities is to organise a pre-kill meeting once the well has been shut-in. The purpose of this meeting is to ensure that all those involved in the supervision and implementation of the well control operation are familiar with the procedures that will be used to kill the well. This meeting is also the first stage in the process of communication during the well control operation.

Experience has shown that even the most well conceived well control procedures can go badly wrong if communication before and during the operation is not properly organised and effective.

It is therefore most important that the well control contingency plan details the method and line of communication for each individual involved in the operation.

The objectives of a suitable system of communication are:

• To ensure that all information relevant to the well control operation is communicated to the Company Representative.

• To ensure that those involved in the supervision of the operation are at all times in communication with the Company Representative.

• To ensure that all those involved in the operation are aware of the line and method of communication that they should use.

• To ensure that communication equipment on the rig is adequate, and is used during the well control operation in the most effective manner possible.

Figure 1.4 shows an example of a possible communication system on a semi-submersible␣rig for use during standard well control operations. The following can be noted from this example: • After the kick is taken, the well is shut-in and closely monitored.

• The Company Representative calls a pre-kill meeting of those involved in the supervision of the operation.

• Responsibilities are allocated to those involved in the operation by the supervisors who attended the meeting.

• Each line and method of communication is defined. It should be noted that: – The rig telephone system is not overloaded.

– The most important lines of communication to and from the Company Representative (denoted by those inside the broken line) are best maintained with the use of hand held radios.

– The use of intrinsically safe hand held radios ensures that all those inside the broken line can listen in on each others communication.

– Depending on the type of operation it may be necessary to include others within the broken line.

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March 1995

Figure 1.4 An Example Communication System

1-13/14 COMPANY REPRESENTATIVE COMPANY DRILLING ENGINEER SENIOR CONTRACTOR REPRESENTATIVE

TOOLPUSHER MUD ENGINEER MUD LOGGING ENGINEER (2) PREKILL MEETING

(1) KICK TAKEN – WELL SHUT-IN – WELL BEING MONITORED

(3) ALLOCATE RESPONSIBILITIES MUD ENGINEER SENIOR CONTRACTOR REPRESENTATIVE SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER CONTRACTOR STAFF MATES OFF DUTY DRILL CREW SUBSEA ENGINEER CONTRACTOR SHOREBASE DRILLER PUMPMAN/ DERRICKMAN DRILL CREW

(4) MAJOR LINES/METHOD OF COMMUNICATION DURING THE WELL CONTROL OPERATION

MUD ENGINEER TOOLPUSHER MARINE STAFF PUMPMAN/ DERRICKMAN DRILLER CONTRACTOR SHOREBASE COMPANY REPRESENTATIVE SERVICE COMPANY ENGINEERS COMPANY SHOREBASE DRILL CREW MUD LOGGING ENGINEER SUBSEA ENGINEER RT S/S RT RT H/H S/S H/H H/H RT RT

RT – RIG TELEPHONE SYSTEM S/S – SHIP TO SHORE H/H – HAND HELD SET

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March 1995

1.3 DRILLS AND SLOW CIRCULATING RATES

Paragraph

Page

1 General 1-16

2 BOP Drills 1-16

3 D1: Kick while Tripping 1-17

4 D2: Kick while Drilling 1-17

5 D3: Diverter Drill 1-19

6 D4: Accumulator Drill 1-19

7 D5: Well Kill Drill 1-21

8 Slow Circulating Rate Pressures, SCRs 1-22

9 Choke Line Losses 1-23

Illustrations

1.5 SCR Pressure Plot 1-23

1.6 Choke Line Pressure Loss Data Sheet 1-25

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March 1995

1 General

Both BOP Drills and the recording of slow circulating rate pressures will be carried out on a routine basis on all rigs.

This section covers the reasons why it is necessary to carry out BOP Drills, to regularly record SCRs, as well as recommended procedures.

2 BOP Drills

The purpose of BOP Drills is to familiarise the drillcrews with techniques that will be implemented in the event of a kick.

One of the major factors that influences the wellbore pressures after a kick is taken is the volume of the influx. The smaller the influx, the less severe will be the pressures during the well kill operation. In this respect, it is important that the drillcrew react quickly to any sign that an influx may have occurred and promptly execute the prescribed control procedure. Drills should be designed to reduce the time that the crew take to implement these procedures. The relevant Drills should be carried out as often as is necessary, and as hole conditions permit, until the Company Representative and the Contractor Toolpusher are satisfied that every member of the drillcrew is familiar with the entire operation.

Every effort must be made to ensure that the Drill is carried out in the most realistic manner possible. Where practical, there should be no difference between the Drill and actual control procedures.

Once satisfactory standards have been achieved, the Drills (D1, D2 and D3, as appropriate) should be held at least once per week. If standards fall unacceptably, the Company Representative should stipulate that the Drills are conducted more frequently.

It is important that returning drillcrews have frequent Drills. The following Drills should be practised where applicable: D1 – Tripping

D2 – Drilling D3 – Diverter D4 – Accumulator D5 – Well Kill

(Suffix R to be included if the remote panel was used)

These codes should be used to record the results of the Drill on the BOP Drill Record Proforma. This form should be sent to the Drilling Superintendent fortnightly. The results of each Drill must also be recorded on the IADC Drilling Report.

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March 1995

3 D1: Kick while Tripping

The purpose of this Drill is to familiarise the crew with the shut-in procedure that will be implemented in the event of a kick during a trip. This Drill should only be conducted when the BHA is inside the last casing string.

Before the trip is started, the Standing Orders to the Driller will have been posted. This will detail the action that the crew should take in the event a kick is detected.

When directed by the Company Representative, the Contractor Toolpusher will instruct the Driller to assume that a positive flowcheck has been conducted, and to implement the prescribed control procedure as detailed in the Standing Orders.

Shut-in procedures to be adopted in the event of a kick while tripping are detailed in Chapter␣4. However, as a guideline the following procedure should be initiated:

• Without prior notice, the Company Representative will start the Drill by manually raising the trip tank float to indicate a rapid pit gain.

• The Driller is expected to take the following steps to shut in the well:

1. Stop other operations.

2. Install the drillpipe safety valve. 3. Open the choke line valve. 4. Close the annular preventer.

5. Record the casing and drillpipe pressure.

6. Notify the Company Representative that the well is shut-in. 7. Record the time for the Drill on the IADC Drilling Report.

The Contractor Toolpusher must ensure that the crew are correctly deployed and that each individual completely understands his responsibilities.

The time taken for the crew to shut in the well should be recorded.

Having shut-in the well, preparations should be made to strip pipe. These preparations should include lining up the equipment as required, assigning individual responsibilities and preparing the Stripping Worksheet.

4 D2: Kick while Drilling

The purpose of this Drill is to familiarise the crew with the control procedure that will be implemented in the event of a kick while drilling.

This Drill may be conducted either in open or cased hole. However if the drill is conducted when the drillstring is in openhole, the well will not be shut-in.

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When the pipe is on bottom, the following procedure can be used as a guideline for the drill: • Without prior notice, the Company Representative gradually increases the apparent pit

level by manually raising the float.

• The Driller is expected to detect the pit gain and take the following steps:

1. Pick up the kelly (or topdrive) until the tool joint clears the BOPs and the kelly cock is just above the rotary table.

2. Shut down the pumps. 3. Check the well for flow.

4. Report to the Company Representative.

5. Record the time required for the crew to react and conduct the Drill on the IADC drilling report.

When the bit has been tripped to the previous casing shoe, a further Drill may be conducted that will result in the well being shut-in.

Therefore after tripping the bit to the shoe, the following procedure may be used as a guideline for this Drill:

• Stop tripping operations and install the kelly (or topdrive) and start circulating. • Having been instructed to do so by the Company Representative, the Driller is expected

to take the following steps to shut-in the well:

1. Pull up until the tool joint clears the BOPs. 2. Shut down the pumps.

3. Open the choke line valve. 4. Close the annular preventer.

5. Record the casing and drillpipe pressure.

6. Double check spaceout, close and lock hang-off rams and hang-off pipe and check that the kelly cock is just above the rotary table.

7. Notify the Company Representative that the well has been shut-in. 8. Record the time taken for the crew to shut-in the well on the IADC drilling

report.

* If on a floating rig

The procedures adopted during these Drills should be in line with the shut-in procedures as outlined in the Standing Orders. These procedures are outlined in Chapter 4.

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5 D3: Diverter Drill

If shallow gas is encountered and the well kicks, blowout conditions may develop very quickly. It is therefore important that crew initiate control procedures as soon as possible in the event of a shallow gas kick.

Diverter Drills should therefore be carried out to minimise the reaction time of the crews. A further objective of the Drill is to check that all diverter equipment is functioning correctly. The time taken for each diverter function to operate should be recorded. A Drill should be carried out prior to drilling out of the conductor casing.

The procedures that should be implemented in the event of a shallow gas kick are covered in Chapter 4. Drills should be designed in line with the specific procedure that will be adopted in the event of a shallow gas kick.

The Contractor Toolpusher must ensure that the drill crew, and marine staff (offshore), are correctly deployed during the Drill and that each individual understands his responsibilities. The time recorded in the log should be the time elapsed from initiation of the Drill until the rig crew (and marine staff) are ready to initiate emergency procedures.

6 D4: Accumulator Drill

The purpose of the Accumulator Drill is to check the operation of the BOP closing system. The following specific tests are recommended:

(a) Accumulator precharge pressure test

This test must be conducted on each well prior to spudding and approximately every 30␣days thereafter at convenient times.

On closing units with two or more banks of accumulator bottles, the hydraulic fluid line to each bank must have a full opening valve to isolate individual banks. The valves must be in the open position except when accumulators are isolated for testing, servicing or transporting. The precharge test should be conducted as follows:

1. Shut-off all accumulator pumps.

2. Drain the hydraulic fluid from the accumulator system into the closing unit fluid reservoir.

3. Remove the guard from the valve stem assembly on top of each accumulator bottle. Attach the charging and gauging assembly to each bottle and check the nitrogen precharge.

4. If the nitrogen precharge pressure on any bottle is less than the minimum acceptable precharge pressure listed below, recharge that bottle (with nitrogen gas only) to achieve the specified desired precharge pressure. 5. If the nitrogen precharge on any bottle is greater than the maximum acceptable precharge pressure listed below, a sufficient volume of nitrogen gas must be bled from the accumulator bottle to provide the specified desired precharge pressure.

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Accumulator Desired Min. Acceptable Max. Acceptable

Working Pressure Precharge Precharge Precharge

Rating Pressure Pressure Pressure

1500 psi 750 psi 750 psi 850 psi

2000 psi 1000 psi 950 psi 1100 psi

3000 psi 1000 psi 950 psi 1100 psi

(b) Accumulator closing test

This test should be conducted before BOP stack tests. The test should be conducted as follows:

1. Position a joint of drillpipe in the blowout preventer stack. 2. Close off the power supply to the accumulator pumps. 3. Record the initial accumulator pressure.

The pressure should be the designed operating pressure of the accumulators. Adjust the regulator to provide 1500 psi operating pressure to the annular preventer.

4. Operate the sequence of functions as relevant to the rig type.

For a land rig:

Close the annular preventer and one pipe ram (sized for the pipe in the stack). Open the HCR valve on the choke line.

For the floating rig:

Close and open all the well control functions (apart from blind/shear rams). Duplicate the operation of the blind/shear rams.

After each function, record the volume used, the time taken, and the residual accumulator pressure. The residual accumulator pressure after completing all the tests must be at least 200 psi greater than the precharge pressure.

5. Turn on the accumulator pumps.

Having completed the tests, recharge the accumulator system to its designed operating pressure. Record the time taken to recharge the system.

(c) Closing unit pump test

Prior to conducting any tests, the closing unit reservoir should be inspected to be sure it does not contain any foreign fluid or debris. The closing unit pump capability test should be conducted before BOP stack tests. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. The test should be conducted according to the following procedure.

1. Position a joint of drillpipe in the blowout preventer stack.

2. Isolate the accumulators from the closing unit manifold by closing the required valves.

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3. If the accumulator pumps are powered by air, isolate the rig air system from the pumps.

A separate closing unit air storage tank should be used to power the pumps during this test. When a dual power (air and electric) source system is used, both power supplies should be tested separately.

4. Close the annular preventer and open one choke line failsafe valve (or␣HCR valve).

Record the time (in seconds) required for the closing unit pumps to close the annular preventer plus open the choke line valve and obtain 200 psi above the accumulator precharge pressure on the closing unit manifold. It is recommended that the time required for the closing unit pumps to accomplish these operations does not exceed two minutes.

5. Close the choke line failsafe (or HCR valve) and open the annular preventer.

Open the accumulator system to the closing unit and charge the accumulator system to its designed operating pressure using the pumps.

7 D5: Well Kill Drill

The objective of this Drill is to give drillcrews the most realistic type of well control␣training and a feel for the equipment and procedures that they would use to kill a well.

This Drill should be carried out prior to drilling out the intermediate and production strings. It should never be carried out when openhole sections are exposed. The following procedure is recommended:

1. Run in hole and tag the top of cement.

2. Pull back one stand and install the kelly (or install topdrive). 3. Break circulation and establish slow circulating rate pressures.

(Consider circulating bottoms up prior to this if the annulus may contain contaminated mud).

4. Carry out standard BOP Drill D2, resulting in the well being shut-in. 5. Consider applying low pressure to the casing (typically 200 psi), bring the

pump up to kill speed controlling the drillpipe pressure according to a predetermined schedule.

It is important that this opportunity to circulate across a choke is used to maximum effect. A drillpipe pressure schedule should be drawn up and carefully adhered to.

It is important that the choke operator develops a feel for the lag time between manipulation of the choke and its subsequent effect on the drillpipe pressure. The lag time should be recorded, so that it can be used for reference should a kick be taken in the next hole section.

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8 Slow Circulating Rate Pressures, SCRs

There are many reasons why a kick should be displaced from the hole at a rate that is considerably slower than that used during normal drilling. These include:

• To minimise the pressure exerted on the openhole. • To allow weighting of the mud as the kick is displaced. • To permit adequate degassing of the returned mud. • To limit the speed of required choke adjustments.

• To reduce the pressure exerted on well control equipment.

All these factors must be taken into account when deciding at what rate to displace the kick. However the absolute upper limit for the displacement rate may be restricted by the pressure rating of the surface equipment, in particular the setting of the pump relief valve. It should be noted that it is potentially hazardous to displace a kick from the hole when the surface pressure is close to the relief valve setting.

In order to estimate the circulating pressures during the displacement of a kick, it is necessary to know the friction pressure in the circulating system at low rates. For this reason, it is useful to have determined the SCR pressure before a kick is taken.

At a given rate of circulation, the initial circulating pressure can be estimated from the sum of the shut-in drillpipe pressure and the SCR pressure.

Company policy states that SCRs should be conducted regularly and at least: • Once per tour (or at 300m intervals during the tour).

• When the bit is changed. • When the BHA is changed.

• When the mud weight or properties are changed.

The range of circulation rates used will be dependent upon many factors, but should fall within the limits of 1/2 and 4 barrels per minute. If oil base mud is in the hole, when back on bottom after a trip, circulate bottoms up before measuring SCRs.

At these relatively low pump speeds the volumetric efficiency of the rig pumps may be significantly less than at normal speeds used during drilling. It is therefore recommended that the volumetric efficiency of the rig pumps is checked at low pump speed, such as when pumping a slug prior to a trip.

It is useful to plot the SCRs on a graph as shown in Figure 1.5. The drillstring internal friction should be calculated at the SCRs and used to determine the annulus frictional pressure as shown. The annulus frictional pressure is a major factor that will influence the rate at which the kick will be displaced from the hole (using standard well control procedure the annulus frictional pressure will be added to wellbore pressure as the pump is brought up to speed to kill the well).

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1-23 March 1995 SCR1 SCR2 SCR3 PSCR1 PSCR2 PSCR3

STANDPIPE PRESSURE (psi)

Drillstring internal pressure drop

Annulus pressure drop

Other SCRs can be selected to displace the kick

PUMP OUTPUT (bbls/min) (stks/min)

WEOX02.005

Figure 1.5 SCR Pressure Plot

A graph similar to Figure 1.5 aids the selection of circulation rates other than these actually measured and also provides a guide to the size of the annulus circulating losses over a range of circulation rates.

9 Choke Line Losses

The frictional pressure caused by circulating through the choke line, while displacing a kick from the well, can cause additional pressures to act in the wellbore.

These pressures are not significant in the case of land, platform and jack-up rigs, but can be critical in the case of a floating rig.

In most cases however, if the correct procedures are adhered to, the choke line frictional pressure should be accounted for as the kick is displaced out of the hole. The recommended method is to monitor the wellhead pressure through the kill line as the pump is started. If the wellhead pressure remains constant as the pump is brought up to speed then the choke line friction will in most cases be automatically compensated for. (This technique is outlined in detail in Chapter 6.)

It is also possible to account for the choke line losses by reducing the choke pressure by an amount equal to the choke line loss as the pump is brought up to speed. This method is not considered to be as reliable as using the kill line monitor.

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It is important that the choke line frictional pressure is accurately known at a wide range of circulating rates. From this information the additional load on the wellbore can be assessed at a range of displacement rates and subsequently the most suitable rate can be selected. The following procedure should be implemented in order to properly assess the choke line frictional pressures at slow circulating rates. This procedure should be carried out initially when the BOP and riser are installed and before drilling out of each subsequent casing shoe.

1. Install suitable pressure gauges to record standpipe and choke pressures during circulation.

2. Record SCR pressure at a range of rates from 1/2 to 4 bbl/min down drillpipe and up the riser.

3. Open choke line valves.

4. Line up choke manifold to route flow across a fully opened remote operated choke. Route returned flow through the poorboy gas separator to the shakers.

5. Space out to ensure no tool joint is opposite annular preventer. 6. Close annular preventer.

7. Circulate down the drillpipe and up through the choke line until returns are uniform.

8. Record SCR pressure at same rates as before. Record the choke pressure at each rate.

9. Calculate the choke line frictional pressure at each rate.

Figure 1.6 shows a form that can be used to record the data. The form also shows how to determine the choke line friction pressure from the recorded data. Figure 1.7 shows an example determination of choke line losses.

The choke line losses should be adjusted for changes in mud weight as shown on the form. The accuracy of this adjustment is however questionable over a wide range of mud weights. In order to verify choke line losses after drilling out of the casing shoe, it is acceptable to isolate the well and pump down the choke line at the range of slow circulating rates.

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BP WELL CONTROL MANUAL

1-25

Mar

ch 1995

Choke Line Pressure Loss Data Sheet

CIRCULATION RATE (bbl/min) WELL No (1) (2) (3) (2)-(1)-(3) RIG DATE RECORDED BY WELL STATUS DURING TEST

CHOKE LINE PRESSURE LOSS DATA SHEET

PROPERTIES OF THE MUD IN THE HOLE DURING THE TEST

………in LINER PUMP RATE (SPM) ………in LINER PUMP RATE (SPM) SCR PRESSURE UP RISER (psi) SCR PRESSURE UP CHOKE LINE (psi) 6.5 25 RIG 19 25/7/87

133_/₈_{in CASING RUN AND TESTED / 13}5_/₈_{in STACK INSTALLED AND TESTED}

1.4SG OBM/PV24CP/YP100 lb/100ft2 _{J. P.}

4.78 40 985

RIG PUMPS: NATIONAL 12 - P - 160

CEMENT PUMP - HT - 400 (4in PLUNGER)

1435 80 370 3.58 30 680 985 55 250 2.39 20 400 590 40 150 1.00 120 190 25 45 0.5 50 65 0 10 0.25 0 0 0 0 CHOKE PRESSURE AT SCR (psi) MEASURED CHOKE LINE LOSS AT……… MUD WEIGHT (psi) CORRECTED CHOKE LINE LOSS AT……… MUD WEIGHT (psi) CORRECTED CHOKE LINE LOSS AT……… MUD WEIGHT (psi) CORRECTED CHOKE LINE LOSS AT……… MUD WEIGHT (psi) 1.4 SG WEOX02.006

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Figure 1.7 An example Determination of Choke Line Losses

400

CIRCULATING @ 20SPM UP RISER

PSCR @ 20SPM = 400psi

600 CIRCULATING @ 20SPM UP CHOKE LINE (CHOKE WIDE OPEN)

POC = 50psi

50

PCL = PSCR (up choke line) – PSCR (up riser) – POC = 600 – 400 – 50

PCL = 150psi

where _{PSCR = Slow Circulating Rate Pressure (psi)} PCL = Choke Line Pressure Loss at SCR (psi) POC = Choke Pressure recorded at SCR with choke wide open (psi)

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1.4 USE OF THE MUD SYSTEM

Paragraph

Page

1 General 1-28

2 Pit Management 1-28

3 Building Mud Weight 1-29

4 Dealing with Gas at Surface 1-31

5 Chemical Stocks 1-34

Illustrations

1.8 An example Mud Gas Separator 1-32

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1 General

Well control contingency plans should outline the manner in which the mud system will be utilised during standard well control operations.

This section is intended to highlight the major factors that will determine the most satisfactory arrangement of the mud system in such circumstances.

2 Pit Management

The following guidelines should be considered when specifying pit arrangements: (a) While drilling a critical hole section

• Keep the active mud system surface area as small as is practical to ease kick detection. Any reserve mud stocks in the tanks should be positively isolated from the active system. Ensure that the gates on the trough are sealing properly.

• Adequate reserve stocks of mud should be held; the volume and weight of which will be determined by the nature of the next hole section.

• Ensure all pit level systems and tank isolating valves are working correctly before drilling into possible gas-bearing zones.

• Keep all mud treatments and pit transfers to the absolute minimum at critical sections of the well. Ensure that the Driller and the Mud Logging Engineer are aware in advance of any changes to the system.

• Crew safety meetings should discuss the problem of gas kicks, especially if oil based mud is in use, and emphasise the importance of early detection. Mud engineering and mud logging personnel should attend these meetings.

(b) When displacing a kick

The major factors that will determine the most satisfactory pit arrangement for displacing a kick include the following:

• The technique that will be used to displace the kick.

• The usable surface pit volume in relation to the hole volume. • The method of weighing up the mud.

• How to deal with the kick when it is displaced to the surface.

• How to deal with the pit gain caused by influx expansion during displacement. • How to deal with contaminated returns.

• The nature and toxicity of the influx fluid. • The monitoring of pit levels in the active system.

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The kick can be displaced from the hole using either the Wait and Weight Method or the Driller’s Method. The most satisfactory arrangement of the pits will be different for each technique and clearly will be rig-specific. There are three different stages at which the mud can be weighted up for these two techniques:

• The Wait and Weight Method

– In a typical situation when it is impractical to weight up a complete hole volume prior to displacement of the kick. This will therefore entail that some mud is weighted while the kick is displaced from the hole. The volume that is weighted prior to displacement of the kick will depend, for a given hole capacity, on the rate at which baryte can be added into the system in relation to the desired rate of displacement. – In the unusual situation when there is adequate surface volume, a complete hole

volume of kill mud can be prepared before displacement of the kick. • The Driller’s Method

– In this case the mud is weighted either while the kick is displaced with original weight mud or after the first circulation depending on the availability of baryte and tank space.

3 Building Mud Weight

(a) Baryte delivery to the mud pits

The rate at which baryte can be added to the original mud influences the time required to increase the weight of a volume of mud. For this reason it is important to measure the rate at which both the conventional hopper system and the high rate system (if fitted) can supply baryte.

If the Driller’s Method is used this will determine the time required to build the mud weight after the kick has been displaced from the hole.

If the Wait and Weight Method is used, the maximum rate at which baryte can be supplied to the mud will:

• Determine the time required to weight the hole volume of mud before the kick is displaced.

• Or it may limit the rate at which the kick can be displaced, if the mud is weighted as the kick is displaced.

The maximum rate at which the mud can be weighted can be determined for a given required mud weight increase from the following formula:

Maximum possible rate = Baryte delivery rate (lb/min) at which the mud can Baryte required to weight up (lb/bbl) be weighted (bbl/min)

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Therefore for the following example:

Required mud weight increase = 0.2 SG (from 1.5 SG to 1.7 SG) Baryte required = 1490 X (1.7 - 1.5) = 117 lb/bbl

4.25 - 1.7

If the maximum barytes delivery rate for the rig = 350 lb/min Then:

Maximum rate at which the = 350 = 3 bbl/min

mud can be weighted 117

This figure therefore gives an indication of the maximum displacement rate if the mud is weighted as the kick is displaced from the hole.

(b) Baryte storage

When possible at least one full barytes storage tank should be pressured up at all times and the bulk delivery system tested regularly.

The bulk system should be included in the rig PMS (Preventive Maintenance) system. (c) Building viscosity into the mud

There may be well control situations which require that considerable volumes of weighted mud are built from a water or oil base. This may be the case in the following situations: • If considerable losses are experienced.

• If the required volume of kill weight mud is greater than the surface stocks of active and reserve weighted mud.

• If the returns are severely contaminated and have to be dumped.

The limiting factor for an oil base mud may be the rate at which viscosity can be built into the base oil. Building viscosity is usually a less important factor when water base muds are used.

Shear equipment is required for building viscosity using clay viscosifiers in new base oil. Some offshore rigs have jet line mixers to help build viscosity.

In circumstances in which large volumes of new oil mud must be built, it would be useful to know the rate at which new mud can be sheared to a level at which barytes can be suspended.

This rate is determined by shearing a known volume of new mud until the minimum viscosity is reached. As a guideline, the minimum viscosity would be represented by a yield point of 10, and a 10 second gel reading of 3.

In emergency situations, viscosity can be built quickly using an oil mud polymer (Baroid’s LFR 2000 as an example) at 4 lb/bbl in conjunction with organophilic clays. However, it is recognised that these polymers can cause high temperature gelation of the mud, and as such, they are not recommended for use in high temperature wells.

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(d) Volume increase due to baryte addition

The volume of a given amount of mud will increase as baryte is added to it. This may be significant when large mud weight increase is required in a large volume of mud. The volume increase due to baryte addition can be determined from the following relationship:

Volume increase = 1.48 bbl per metric ton of baryte added Therefore in the following situation:

The required addition of baryte = 200 lb/bbl Volume to weight up = 600 bbl

Volume increase due to baryte addition = 600 X 200 X 1.48 = 80 bbl

2205

4 Dealing with Gas at Surface

It is important that suitable equipment is available on the rig to deal with the influx once it is displaced to surface.

Returns should be piped through the mud gas separator and then on to the degasser for further treatment.

(a) The mud gas separator (poorboy)

The mud gas separator should be lined up at all times when a kick is being displaced. The separator is used to remove large gas bubbles from the mud and to deal with a flow of gas once the influx is at surface.

There will be a limit to the volume of gas that each separator can safely deal with. When this limit is exceeded, there exists the possibility that gas will blow through into the shaker header box.

An estimation can be made of the maximum gas flowrate that the separator can handle. The limiting factors will be the back pressure at the outlet to the vent line in relation to the hydrostatic head of fluid at the mud outlet of the separator. When the back pressure due to the gas flow is equal to, or greater than, the hydrostatic head available at the mud outlet, the gas will blow through to the shaker header tank. See Figure 1.8.

In order to minimise the possibility of a gas blow-through, the vent line should be as straight as possible and have a large ID. The mud outlet should be configured to develop a suitable hydrostatic head (minimum recommended head is 10 feet). See Figure 1.8.

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The back pressure due to the flow of gas should be monitored with a pressure gauge as shown in Figure 1.8. Some warning of the possibility of a gas blow-through will be given when the registered pressure approaches the hydrostatic head of the fluid in the discharge line. It should be noted that the maximum hydrostatic head available may not be that of the mud in the event that large volumes of oil or condensate are displaced to␣surface.

If the safe operating limit of the separator is approached, the choke can be closed in (while ensuring that the well is not overpressured) or the flow switched to the overboard line or the burn pit.

Figure 1.8 An example Mud Gas Separator

– operating at maximum capacity

INSPECTION COVER

GAS OUTLET

8in ID MINIMUM

GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi) INSPECTION COVER SECTION A-A TANGENTIAL INLET TO SHAKER HEADER TANK 2in DRAIN OR FLUSH LINE 4in CLEAN-OUT PLUG A A 10ft MINIMUM HEIGHT 8in NOMINAL ‘U’ TUBE BRACE 30in OD STEEL TARGET PLATE INLET HALF CIRCLE BAFFLES ARRANGED IN A ‘SPIRAL’ CONFIGURATION

4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD

MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.75 SG GIVES 7.6psi MAXIMUM CAPACITY

10ft APPROX APPROX

HEIGHT 1/2 OF

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(b) The degasser

The degasser should be lined up at all times during the well control operation.

The degasser is designed to remove the small bubbles of gas that are left in the mud after the mud has been through the mud gas separator.

It is important that the degasser is working properly and as such it should be tested every tour. While drilling with gas cut returns, the degasser can be checked as follows:

1. Measure actual (gas cut) mud weight at the shaker header box using a non pressurised mud balance.

2. Measure actual mud weight at the degasser outlet using a non pressurised mud balance.

If the actual mud weight at the outlet of the degasser is greater than the actual mud weight at the inlet, then the degasser is working. If the mud weight at this stage is not equal to the active system mud weight, then either the degasser is not working properly, or the returns are at a lower weight than the mud in the active system. If the actual mud weight measured at this stage is equal to the active system mud weight, then the degasser is working properly.

3. Measure mud weight at the degasser outlet and the shaker header box using a pressurised mud balance.

If the actual mud weight at the outlet of the degasser is equal to the reading on␣the pressurised mud balance, the degasser has removed all the gas from the mud. (c) Overboard lines/Flare lines

It is recommended that a second method of dealing with severely gas cut returns be available at the rigsite, whether on land or offshore. This will generally be either an overboard line, or a flare line to the burn pit on land.

It should be easy to switch the returns from the mud system to the flare line. It may be necessary to use the flare line during a well control operation in the following situations: • The gas flowrate is too high for the mud gas separator.

• Hydrates are forming in the gas vent line from the mud gas separator. • The gas is found to contain H₂S.

• The mud system is overloaded.

Lines that are required to handle high velocity gas must be as straight as possible to minimise erosion. Significant erosion is likely to occur in the path of high velocity gas and solids, therefore the redundancy in flowlines and manifolds downstream of the choke must be analysed on all rigs.

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5 Chemical Stocks

(a) Baryte and mud chemical stocks

Company policy details the minimum stocks of baryte and mud chemicals that should be held at the rigsite. The policy states that:

‘Sufficient weighting material stocks must be maintained on site such that the entire mud circulating volume can be raised by a minimum of 0.25 SG (See formula in

Paragraph 3). Reserve stocks of bentonite or viscosifier must also be on site to enable this increase in mud weight to be effected’.

‘Where transport and logistics are not assured (offshore and remote locations) the minimum onsite weighting material stock must be 100 tonnes’.

This is a minimum standard, and as such, the Company Representative may wish to stock a greater quantity of baryte and chemicals.

(b) Cement stocks

Cement stocks should not drop below the quantity of cement and additives that will be required to set 2 X 150m of cement plugs in the hole section being drilled.

Additionally, in high pressure wells, an abandonment plug recipe should be onsite prior to drilling into the reservoir. Batch mix tanks should also be onsite during the drilling of such reservoir sections.

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1.5 KICK TOLERANCE

Paragraph

Page

1 General 1-36

2 Kick Tolerance Calculation Methods 1-36

3 Procedure for Kick Tolerance Calculations 1-37

4 Considerations for High Angle and Horizontal Wells 1-40

5 When to Calculate Kick Tolerance 1-41

6 Excel Kick Tolerance Calculator 1-42

Illustrations

1.9 Kick Tolerance Values Through a Zone

of Increasing Pore Pressure 1-43

1.10 Excel Kick Tolerance Calculator – Example Calculations 1-44