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OISD-RP-174 Second Edition

July 2008 For Restricted Circulation

WELL CONTROL

OISD RP 174

Prepared by

FUNCTIONAL COMMITTEE FOR REVIEW OF WELL CONTROL

OIL INDUSTRY SAFETY DIRECTORATE 7th Floor, New Delhi House,

27, Barakhamba Road, New Delhi 110 001.

www.oisd.gov.in

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NOTE

OISD (Oil Industry Safety Directorate) publications are prepared for use in the Oil

and Gas Industry under Ministry of Petroleum & Natural Gas. These are the property of

Ministry of Petroleum & Natural Gas and shall not be reproduced or copied and loaned or

exhibited to others without written consent from OISD.

Though every effort has been made to assure the accuracy and reliability of the data

contained in the document, OISD hereby expressly disclaims any liability or responsibility

for loss or damage resulting from their use.

The document is intended to supplement rather than replace the prevailing statutory

requirements.

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FOREWORD The Oil Industry in India is 100 years old. Because of various collaboration agreements, a variety of international codes, standards and practices have been in vogue. Standardisation in design philosophies and operating and maintenance practices at a national level was hardly in existence. This coupled with feed back from some serious accidents that occurred in the recent past in India and abroad, emphasised the need for the industry to review the existing state of art in designing, operating and maintaining oil and gas installations. With this in view, the Ministry of Petroleum and Natural Gas in 1986 constituted a Safety Council assisted by the Oil Industry Safety Directorate (OISD) staffed from within the industry in formulating and implementing a series of self regulatory measures aimed at removing obsolescence, standardising and upgrading the existing standards to ensure safe operations. Accordingly, OISD constituted a number of functional committees of experts nominated from the industry to draw up standards and guidelines on various subjects. The recommended practices for "Well Control" have been prepared by the Functional Committee for revision of Well Control". This document is based on the accumulated knowledge and experience of industry members and the various national / international codes and practices. This document covers recommended practices for selection of well control equipment, installation requirements of well control equipment, inspection and maintenance of well control equipment, methods for well control and competence of personnel. Well Control issues related to both onland and offshore operations have been covered. Suggestions are invited from the users after it is put into practice to improve the document further. Suggestions for amendments to this document should be addressed

The Coordinator

Functional Committee on

Well Control,

Oil Industry Safety Directorate,

7thFloor, New Delhi House,

27, Barakhamba Road,

New Delhi -110 001.

Email: oisd@vsnl.com

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COMMITTEE FOR PREPARING STANDARD ON "WELL CONTROL"

1998 ----------------------------------------------------------------------------------------------------------------------------- Name Designation & Position in Organisation Committee ---------------------------------------------------------------------------------------------------------------------------- 1.S/Shri .A.K. Hazarika GM(D) Leader ONGC, Mumbai 2. S.L. Arora GM(D) Member ONGC, Ahmedabad 3. A. Borbora Dy. CE(D) Member OIL, Duliajan 4. C.S. Verma Dy. CE(D) Member Oil, Rajasthan 5. A. Verma CE(P) Member ONGC, Mumbai 6. V.P. Mahawar CE(D) Member ONGC, Dehradun 7. B.K. Baruah DGM(D) Member ONGC, ERBC 8. S.K. Ahuja SE(D) Member ONGC, ERBC 9. P.K. Garg Addl. Director (E&P) Co-ordinator ----------------------------------------------------------------------------------------------------------------------------

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Functional Committee for Complete Review of OISD-STD-174, 2008

LEADER Shri K. Satyanarayan Oil and Natural Gas Corporation Ltd., Ankleshwar.

MEMBERS Shri V.P. Mahawar Oil and Natural Gas Corporation Ltd., Ahmedabad.

Shri R.K. Rajkhowa Oil India Ltd., Duliajan, Assam.

Shri S.K. Ahuja Oil and Natural Gas Corporation Ltd., Mumbai.

Shri B.S. Saini Oil and Natural Gas Corporation Ltd., Sibsagar, Assam.

Shri A.J. Phukan Oil India Ltd., Duliajan, Assam.

MEMBER COORDINATOR Shri H.C.Taneja Oil Industry Safety Directorate, New Delhi.

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Contents

Section Description Page

1.0 Introduction 1

2.0 Scope 1

3.0 Definitions 1

4.0 Planning for Well Control 3 4.1 Cause of Kick 3 4.2 Cause of Reduction in Hydrostatic Head 3 4.3 Well Planning 3 5.0 Diverter Equipment and Control System 3 5.1 Procedures for Diverter Operations 4 6.0 Well Control Equipment & Control System 4 6.1 Selection 4 6.2 Periodic Inspection and Maintenance 5 6.3 Surface Blow out Prevention Equipment 5 6.4 Subsea Blow out Prevention Equipment 7

6.5 Choke and Kill Lines 10 6.6 Wellhead, BOP Equipment and Choke & Kill Lines Installation 12

6.7 Blow out Preventer Testing 13 6.8 Minimum Requirements for Well Control Equipment 14 for Workover Operations (on land) 7.0 Procedures and Techniques for Well Control (Prevention 15 and Control of Kick) 7.1 Kick Indications 15 7.2 Prevention and Control of Kick 15

7.3 Kick Control Procedures 17

8.0 Drills and Training 21 8.1 Pit Drill (On bottom) 21

8.2 Trip Drill (Drill Pipe in BOP) 21 8.3 Trip Drill (Collar in Blowout Preventer) 22 8.4 Trip Drill (String is out of Hole) 22

8.5 Well Control Training 22 9.0 Monitoring System 22 9.1 Instrumentation Systems 22 9.2 Trip Tank System 22 9.3 Mud Gas Separator (MGS) 23 9.4 Degasser 23

10.0 Under Balanced Drilling 23 10.1 Procedures for UBD 24

11.0 Well Control Equipment Arrangement for HTHP Wells 26

12.0 References 27

Abbreviations 28

Annexure I to VIII

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Recommended Practices for Well Control 1.0 Introduction

Primary well control is by maintaining hydrostatic pressure in the wellbore at least equal to (preferably more than) the formation pressure to prevent the flow of formation fluids. During drilling and workover operations flow of formation fluids into the wellbore is considered as kick. If not controlled, a kick may result in a blowout. For safety of personnel, equipment and environment, it is of utmost importance to safely prevent or handle kicks. This document provides guidance on selection, installation and testing of well control equipment. The recommended practices also include procedures for preventing kicks while drilling and tripping, safe closure of well on detection of kicks, procedures for well control drills, during drilling and workover operations. Recommendations for the surface installations are applicable to sub-sea installations also unless stated otherwise.

All the sections / sub-sections of this document mentioning drilling are relevant to workover operations also, wherever applicable. Terms like drilling fluid means workover fluid in the context of workover operations.

2.0 Scope

This document covers selection, installation and testing of well control equipment both surface and sub-sea, and recommended practices for kick prevention, and control and competence requirement (training and drills) for personnel, in drilling and workover operations.

3.0 Definitions 3.1 Accumulator (BOP Control Unit)

A pressure vessel charged with nitrogen or other inert gas and used to store hydraulic fluid under pressure for

operation of blowout preventers and/or diverter system.

3.2 Annular Preventer A device, which can seal around different sizes & shapes object in the wellbore or seal an open hole.

3.3 Blowout An uncontrolled flow of well fluids and/or formation fluids from the wellbore.

3.4 Blowout Preventer A device attached to the casinghead that allows the well to be sealed to confine the well fluids to the wellbore.

3.5 Blowout Preventer Stack

The assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the casing head.

3.6 Bottomhole Pressure (BHP)

Sum of all pressures that are being exerted at the bottom of the hole and can be written as:

BHP = static pressure + dynamic pressures Static pressure in a wellbore is due to

mud column hydrostatic pressure and surface pressure. Dynamic pressures are exerted due to mud movement or the pipe movement in the wellbore. BHP under various operating situations is:

Not circulating (static condition) BHP = hydrostatic pressure due to mud column While drilling (over balance) BHP = Hydrostatic pressure of mud + annular pressure losses.

While drilling (MPD/UBD) BHP = Hydrostatic pressure of mud + annular pressure losses + Surface annular pressure

While shut-in after taking kick BHP = Hydrostatic pressure +

surface pressure While killing a well BHP = Hydrostatic + surface press. + annular pressure losses Running pipe in the hole BHP = Hydrostatic pressure + surge pressure

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Pulling pipe out of hole BHP = Hydrostatic pressure - swab pressure. 3.7 Choke manifold

The assembly of valves, chokes, gauges, and piping to control flow from the annulus and regulate pressures in the drill string / annulus flow, when the BOPs are closed.

3.8 Degasser A vessel, which utilizes pressure reduction and/or inertia to separate entrained gases from the liquid phases.

3.9 Diverter A device attached to the wellhead or marine riser to close the vertical access and direct flow into a line away from the rig.

3.10 Fracture Pressure The pressure required to initiate a fracture in a sub surface formation (geologic strata). Fracture pressure can be determined by Geo-physical methods; during drilling fracture pressure can be determined by conducting a leak off test.

3.11 Hydrostatic Pressure

Pressure exerted by the fluid column at the depth of interest is termed as hydrostatic pressure. The magnitude of hydrostatic pressure depends upon the density and the vertical height of liquid column. Hydrostatic pressure can be calculated by the following formula. Hyd. pressure (psi) = 0.052 x mud wt.(ppg) x TVD (feet) Hyd. pressure (kg/cm2) = Mud wt.( gm/cc) x TVD (mtrs)/10 where TVD = True vertical depth.

3.12 Influx The flow of fluids from the formation into the wellbore.

3.13 Kick A kick is intrusion of unwanted formation fluids into wellbore, when hydrostatic head of drilling fluid column is / becomes less than the formation pressure. Kick can lead to blowout, if timely corrective measures are not taken.

3.14 Kill Rate Reduced circulating rate (kill rate) is required when circulating kicks so that additional pressure to prevent formation flow can be added without exceeding pump liner rating. Kill rate is normally half of the normal circulating rate. For subsea stacks in deep water, kill rates less than half of the normal circulating rate may be required to avoid excessive back pressure in the choke flow line.

3.15 Kill Rate Pressure The circulating pressure measured at the drill pipe gauge when the mud pumps are operating at the kill rate.

3.16 Marine riser system The extension of the wellbore from the subsea BOP stack to the floating drilling vessel which provides for fluid returns to the drilling vessel, supports the choke, kill, and control lines, guides tools into the well, and serves as a running string for the BOP stack.

3.17 Maximum Allowable Annular Surface Pressure (MAASP) It is maximum allowable annular surface pressure during well control; any pressure above this may damage formation / casing / surface equipment.

3.18 Mud Gas Separator A device that removes gas from the drilling fluid returns, when a kick is being circulated out. Mud gas separator is also known as gas buster or poor-boy degasser.

3.19 Pipe-light

Pipe-light occurs at the point where the formation pressure across the pipe cross-section creates an upward force sufficient to overcome the downward force created by the pipes weight- a potentially disastrous scenario.

3.20 Pore Pressure Pressure at which formation fluid is trapped in the pore (void) spaces of the rock is termed as formation pressure or pore pressure. It can be expressed in various ways like:

In term of pressure - psi or kg/cm2 In term of pressure gradient - psi /ft or

kg/cm2/meter.

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In term of equivalent mud wt. - ppg or gm/cc.

3.21 Shall

The word shall is used to indicate that the provision is mandatory.

3.22 Should The word should is used to indicate that the provision is recommendatory as per sound engineering practice.

3.23 Underbalanced Drilling (UBD) Drilling operation, when the hydrostatic head of a drilling fluid is intentionally (naturally or induced by adding natural gas, nitrogen, or air to the drilling fluid) kept lower than the pressure of the formation being drilled with the intention of bringing formation fluids to the surface.

4.0 Planning for well control 4.1 Cause of Kick

Kick may be caused due to:

i. Encountering higher than anticipated pore pressure.

ii. Reduction in hydrostatic

pressure in the wellbore. 4.2 Cause of Reduction in Hydrostatic

Head

I. Failure to keep the hole full of drilling fluid

II. Swabbing, III. Loss of circulation IV. Insufficient drilling fluid

density. V. Gas cut drilling fluid VI. Loss of riser drilling fluid

column. 4.3 Well Planning

I. Well planning should include conditions anticipated to be encountered during drilling / working over of the well, the well control equipment to be used, and the well control procedures to be followed.

II. For effective well control the following elements of well planning should be considered:

a. Casing design and kick

tolerance b. Cementing c. Drilling fluid density d. Drilling fluid monitoring

equipment e. Blowout prevention equipment

selection f. Contingency plans with

actions to be taken if the maximum allowable casing pressure is reached

g. Hydrogen sulphide environment, if expected.

III. During well planning shallow gas

hazard should also be considered. Well plan should include mitigating measures considering the following:

a. Pilot hole drilling, b. Use of diverter. c. Riserless drilling (with

floater) 5.0 Diverter Equipment and Control

System

A diverter system is used during top-hole drilling; it allows routing of the flow away from the rig to protect persons and equipment. Components of diverter system include annular sealing device, vent outlet(s), vent line(s), valve(s), control system. Recommended practices for diverter system:

I. The friction loss should not exceed the

diverter system rated working pressure, place undue pressure on the wellbore and /or exceed other equipments design pressure, etc., e.g. marine riser. The diverter system should be accordingly designed.

II. To minimise back pressure (as much as

practical) on the wellbore while diverting well fluids, diverter piping should be adequately sized.

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III. Vent lines should be 10 or above for offshore and 8 or above for onshore.

IV. Diverter lines should be straight as far

as possible, properly anchored and sloping down to avoid blockage of the lines with cuttings etc.

V. The diverter and mud return (flow line)

lines should be separate lines. VI. Diverter valves should be full opening

type either pneumatic or hydraulic with automatic sequencing / manual sequencing.

VII. The diverter control system may be self

contained or an integral part of the blowout preventer control system. It should be located in safe area.

VIII. The diverter control system should be

capable of operating the diverter system from two or more locations - one to be located near the driller's console.

IX. When a surface diverter system and a

sub-sea BOP stack are used, two separate control / accumulator systems are required. This will allow the BOPs to be operated and the riser disconnected in case the diverter control system gets damaged.

X. Size of the hydraulic control lines should

be as per manufacturers recommendations.

XI. Control systems of diverter should be

capable of closing the diverter within maximum 45 seconds and simultaneously opening the valves in the diverter lines.

XII. Telescopic/slip joints (in case of floating

rigs) should be incorporated with double seals, to improve the sealing capability when gas has to be circulated out of the marine riser.

XIII. Alternate means to operate diverter

system (in case primary system fails) should be provided.

5.1 Procedures for Diverter Operations

Following procedure is recommended for use of diverter:

I. Stop drilling II. Pick up Kelly until tool joint is above

rotary. III. Open vent line towards downward

wind direction, close diverter packer and close shale shaker inlet valve.

IV. Stop pump and check for flow through

open vent line. V. If flow is positive, pump water or

drilling fluid as required moderating the flow.

VI. Monitor and adjust packer pressure as

and when required. VII. Alert the personnel on the rig. VIII. Take all precautions to prevent fire by

putting off all naked flames and unnecessary electrical systems.

Additionally following are applicable in case of subsea wells:

I. Monitor and adjust slip joint packer pressure as and when required.

II. Watch for gas bubbles in the vicinity of

drilling vessel.

6.0 Well Control Equipment &

Control System 6.1 Selection

I. All the equipment including ram preventers, lines, valves and flow fittings shall be selected to withstand the maximum anticipated surface pressures. Annular preventer can have lower rating than ram BOP.

II. Welded, flanged or hub end

connections are only recommended on all pressure systems above 3000 psi.

III. In sour gas areas H2S trim (refer NACE

MR0175 / ISO 15156) equipment should be used.

IV. Kill lines should be of minimum 2

nominal size and choke line should be of minimum 3 nominal size.

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V. Size of choke line and choke manifold should be same.

VI. Closing systems of surface BOPs

should be capable of closing each ram preventer and annular preventer up to 18 size within 30 seconds and annular preventer above 18 size within 45 seconds.

VII. Closing systems of sub-sea BOPs

should be capable of closing each ram preventer within 45 seconds and annular preventer within 60 seconds.

VIII. Ram type subsea preventers should be

equipped with an integral or remotely operated locking system. Surface ram preventer should be equipped with mechanical / hydraulic ram locks.

6.2 Periodic Inspection and Maintenance

I. The organisation should establish inspection and maintenance procedures for well control equipment. Inspections and maintenance procedures should take into consideration the OEMs recommendations.

II. Inspection recommendations, where

applicable, may include:

a. Verification of instrument accuracy

b. Relief valve settings c. Pressure control switch

settings d. Nitrogen precharge pressure

in accumulators e. Pump systems f. Fluid Levels g. Lubrication Points h. General condition of

i) Piping systems ii) Hoses iii) Electrical conduit/cords iv) Mechanical components v) Structural components vi) Filters/strainers vii) Safety covers/devices viii) Control system adequacy ix) Battery condition

III. Inspections between wells: after each

well, the well control equipment should be cleaned, visually inspected, preventive maintenance performed before installation at the next well. The

inspection should include the seal area of the connectors (Choke and kill lines) for any damage.

IV. Major inspection: after every 5 years of

service or as per OEMs recommendation. The BOP stack, choke manifold, and diverter assembly should be disassembled, and inspected in accordance with the OEMs guidelines.

V. Spare parts requirement as per OEM

should be considered. However, minimum spare parts as listed below should be readily available:

i) A complete set of ram seals for

each size and type of ram BOP in use.

ii) A complete set of bonnet or door seals for each size and type of ram BOP in use.

iii) Ring gaskets to fit end connections.

iv) A spare annular BOP packing element and a complete set of seals.

VI. During storage of BOP metal parts and

related equipment, they should be coated with a protective coating to prevent rust. Storage of elastomer parts should be in accordance with manufacturers recommendations.

VII. System should be in place to control

use of rubber / elastomer parts, having limited shelf life.

VIII. Separate maintenance history / log

book of all the BOPs, Choke manifold and Control unit should be maintained.

IX. All pressure gauges on the BOP control

system should be calibrated at least every three years.

6.3 Surface Blow out Prevention

Equipment

Surface blow out prevention equipment is used on land operations and offshore operations where the wellhead is above the water level.

I. Well control equipment can be classified under the following categories based on pressure rating:

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a) 2000 psi WP b) 3000 psi WP c) 5000 psi WP d) 10000 psi WP e) 15000 psi WP, and f) 20,000 psi WP

II. Refer Annexure-I for recommended 2000 psi BOP stack. One double, or two single ram type preventers - one of which be equipped with correct size pipe rams the other with blind or blind- shear rams.

III. Refer Annexure-II for recommended

3000/5000 psi BOP stack. The stack comprises of, besides annular BOP, one double, or two single ram type preventers - one of which should be equipped with correct size pipe rams and the other with blind or blind-shear rams.

IV. Refer Annexure-III for recommended

10000 / 15000 / 20000 psi BOP stack. The stack comprises of, besides annular BOP, three single, or one double and one single ram type preventers: one of which be should be equipped with blind or blind-shear rams and the other two with correct size pipe rams.

V. When the bottom ram preventer is

equipped with proper size side outlets, the kill and choke lines may be connected to the side outlets of the bottom preventer. In that case the drilling spool may be dispensed with.

VI. Inspite of the above, a drilling spool use

may be considered for the following two advantages:

a. Stack outlets at drilling spool

localizes possible erosion in less expensive drilling spool.

b. It allows additional space

between preventers to facilitate stripping, hang off, and / or shear operations.

6.3.1 Control System for Surface BOP

Stacks (Onshore and Bottom-supported Offshore Installations)

I. Control systems are typically simple closed hydraulic control systems consisting of a reservoir for storing hydraulic fluid, pump equipment for pressurizing the hydraulic fluid, accumulator banks for storing power fluid, manifolding, piping and control valves for transmission of control fluid for the BOP stack functions.

II. A suitable control fluid should be

selected as the system operating medium based on the control system operating requirements, environmental requirements and user preference.

III. Two (primary and secondary) or more

pump systems should be used having independent power sources. Electrical and / or air (pneumatic) supply for powering pumps should be available at all times such that the pumps will automatically start when the system pressure has decreased to approximately ninety percent of the system working pressure and automatically stop within plus zero or minus 100 psi of the system design working pressure.

IV. With the accumulators isolated, the

pump system should be capable of closing annular BOP on the drill string being used, open HCR valve on choke line and achieve the operating pressure level of annular BOP to effect a seal on the annular space within 2 minutes.

V. Each pump system should be protected

from over pressurisation by a minimum of two devices designed to limit the pump discharge pressure. One device should limit the pump discharge pressure so that it will not exceed the design working pressure of a BOP Control System. The second device normally a relief valve, should be sized to relieve at a flow rate of at least equal to the design flow rate of the pump systems, and should be set to relieve at not more than ten percent over the design pressure.

VI. The combined output of all pumps

should be capable of charging the entire accumulator system from precharge pressure to the maximum rated control system working pressure within 15 minutes.

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VII. The hydraulic fluid reservoir should have a capacity equal to at least twice the useable hydraulic fluid capacity of the accumulator system.

VIII. In the field, the precharge pressure

should be checked and adjusted to within 100 psi of the recommended precharge pressure during installation of the control system and at the start of drilling each well (interval not to exceed sixty days).

IX. The BOP control system should have a

minimum stored hydraulic fluid volume, with pumps inoperative, to satisfy the greater of the following two requirements:

a) Close from a full open position at

zero wellbore pressure, all of the BOPs in the BOP stack, plus 50 % reserve.

b) The pressure of the remaining

stored accumulator volume after closing all of the BOPs should exceed the minimum calculated (using the BOP closing ratio) operating pressure required to close any ram BOP (excluding the shear rams) at the maximum rated wellbore pressure of the stack.

X. All rigid or flexible lines between the

control system and BOP stack should be fire resistant including end connections, and should have a working pressure equal to the design working pressure of the BOP control system. All control system interconnect piping, tubing hose, linkages etc. should be protected from damage from drilling operations, drilling equipment movement and day to day personnel operations.

XI. The control unit should be installed in a

location away from the drill floor and easily accessible to the persons during an emergency.

XII. A minimum of one remote control panel

accessible to the driller to operate all system functions during drilling operations should be installed at onshore rigs. In offshore, one control panel shall be available at a non hazardous area preferably tool pusher

office for BOP stack functions, besides the one near the driller.

XIII. Remote control panels should have

light indicators to show open/close/block position of each BOPS and Hydraulically operated choke and kill valves. For onshore it is optional and for offshore unit it is must.

XIV. For offshore units emergency backup

BOP control system should be available. A backup system consists of a number of high pressure gaseous nitrogen bottles manifolded together to provide emergency auxiliary energy to the control manifold. The nitrogen backup system is connected to the control manifold through an isolation valve and a check valve. If the accumulator pump unit is not able to supply power fluid to the control manifold, the nitrogen back-up system may be activated to supply high pressure gas to the manifold to close the BOPs.

6.4 Subsea Blow out Prevention

Equipment

Subsea BOP stack arrangements should provide means to:

I. Close in on the drill string and on the casing or liner and allow circulation.

II. Close and seal on open hole and allow

volumetric well control operations. III. Strip the drill string using the annular

BOP(s). IV. Hang off the drill pipe on a ram BOP

and control the wellbore. V. Shear logging cable or the drill pipe and

seal the wellbore. VI. Disconnect the riser from the BOP

stack. VII. Circulate the well after drill pipe

disconnect. VIII. Circulate across the BOP stack to

remove trapped gas.

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6.4.1 Subsea BOP Stack

Subsea blow out prevention equipment is used on subsea wellhead.

I. Well control equipment can be classified in following categories based on pressure rating.

a) 2000 psi WP b) 3000 psi WP c) 5000 psi WP d) 10000 psi WP e) 15000 psi WP and f) 20,000 psi WP

II. Arrangements for subsea BOP stack at

Annexure IV and V should be referred.

III. Annular BOPs are designated as lower

annular and upper annular. Annular BOP may have a lower rated working pressure than the ram BOPs.

IV. Choke and kill lines are manifolded

such that each can be used for either purpose. The identifying labels for the choke and kill lines are arbitrary. When a circulating line is connected to an outlet below the bottom ram BOP, this circulating line is generally designated as kill line. When kill line is connected below the lowermost BOP, it is preferable to have one choke line and one kill line connection above the bottom ram BOP. When this bottom connection does not exist, either or both of the two circulating lines may alternately be labeled as a choke line.

V. Some differences as compared to

surface BOP systems are:

a. Choke and kill lines are normally connected to ram preventer body outlets to reduce stack height and weight, and to reduce the number of stack connections.

b. Spools may be used to space

preventers for shearing tubulars, hanging off drill pipe, or stripping operations.

c. Blind-shear rams are used in

place of blind rams.

d. Ram preventers should be equipped with an integral or remotely operated locking system.

6.4.2 Control System for Subsea BOP

Stack For subsea operations, BOP operating and control equipment should include:

I. Floating drilling rigs experience vessel motion, which necessitates placement of the BOP stack on the sea floor. The control systems used on floating rigs are usually open-ended hydraulic systems (spent hydraulic fluid vents to sea) and therefore employ water-based hydraulic control fluids.

II. An independent automatic accumulator unit for subsea BOP control system complete with an automatic mixing system to maintain mixed fluid ratios and levels of mixed hydraulic fluids.

III. The accumulator capacity should be

sufficient for closing, and opening all ram type preventers, annular preventers and fail-safe-close valves without recharging accumulator bottles, and the remaining pressure should be either 200 psi above recommended precharge pressure or value based on the closing ratio of ram preventer in use, whichever is more.

IV. The unit should be equipped with two or more pump system driven by independent power source. Capacity of the pumps should meet following:

a. With accumulator isolated, each

pump system should be capable of closing annular preventer and opening fail-safe-close valve of choke within 2 minutes time.

b. Combined output of all the pumps

should be capable of charging accumulator to the rated pressure within 15 minutes.

V. Accumulators should be installed on the

BOP stack for quicker response of the functions, and its precharge pressure should be compensated for water gradient.

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VI. Two full function remote control panels to operate BOP stack functions should be available, out of which one should be accessible to driller on the rig floor. A flow meter for indicating control fluid flow should be located on each remote control panel.

VII. The remote panels should be

connected to the control manifold in such a way that all functions can be operated independently from each panel.

VIII. Two independent control pods with all

necessary valves and regulators to operate all BOP stack functions should be available. Two separate and independent sets of surface and subsea umbilicals should be used, one dedicated to each control pod. Main hydraulic fluid line should be of minimum 1 size.

IX. An emergency control system, either

acoustic system or remotely operated vehicle (ROV) operated control system should be used in the event that the BOP functions are inoperative due to a failure of the primary control system. Emergency control system should charge and discharge stack mounted accumulator, close at least one ram type preventer, blind shear ram and open Lower Marine Riser Package (LMRP) hydraulic connector.

X. The BOP control system should be

capable of closing each ram BOPs and opening or closing fail-safe-close valves within 45 seconds. For annular preventer, closing time should not exceed 60 seconds. Time to unlatch the LMRP should be less than 45 seconds.

XI. Precharge pressure of accumulator

bottle in case of 3000 psi WP unit should be 1000 +/- 100 psi and in case 5000 psi WP unit should be 1500+/- 100 psi. Only Nitrogen should be used for precharge.

XII. Separate diverter control panel should

be available at rig floor to operate all diverter control functions. Second control panel should be provided in the safe and approachable area away from rig floor.

XIII. If diverter control system is not self contained, hydraulic power may be supplied from BOP control system.

XIV. The diverter control system should be

designed to prohibit closing the diverter packer unless diverting lines have been opened.

XV. Air storage backup system should be

provided with capability to operate all the pneumatic functions at least twice in the event of loss of rig air pressure.

XVI. The drilling BOP shall have two

annular preventers. One or both of the annular preventers shall be part of the LMRP. It should be possible to bleed off gas trapped between the preventers in a controlled way.

6.4.3 Deep Water Drilling Operations

For Deep water drilling operations following additional requirements should be met:

I. If two or more different size strings are run, blind-shear ram should be able to shear all sizes of string.

II. Use of two blind-shear rams is preferred for ensuring the backup seal in case of unplanned disconnect.

III. In addition to choke and kill lines, a dedicated boost line shall be provided for riser cleaning with necessary boost line valves above the BOP stack.

IV. In the event of full or partial evacuation of mud from the riser, to combat riser collapse, an anti-collapse valve should be provided in the riser system allowing automatic entry of seawater.

V. ROV should be able to perform following functions:

i. LMRP and wellhead connector

unlatch. ii. LMRP and wellhead ring gasket

release. iii. Methanol / Glycol injection. iv. Opening and closing of pipe

rams and blind-shear rams. v. LMRP and Accumulator Dump.

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VI. The need to utilize a multiplex BOP control system to meet the closing time requirements should be evaluated for application, if required.

VII. The kill-/choke line ID should be verified

vis--vis acceptable pressure loss, to allow killing of the well at predefined kill rates. The kill-/choke line should not be less than 88.9 mm (3 inches).

VIII. It should be possible to monitor the

shut-in casing pressure through the kill line when circulating out an influx by means of the work string / test tubing / tubing.

IX. It should be possible to monitor BOP

pressure and temperature at surface, through appropriate means.

X. It should be possible to flush wellhead

connector with antifreeze liquid solution by using the BOP accumulator bottles or with a ROV system or other methods.

XI. Detailed riser verification analysis

should be performed with actual environment and well data (i.e. weather data, current profiles, rig characteristics etc.) and should be verified by a 3rd party.

XII. A simulated riser disconnect test should

be conducted considering manageable emergency weather / operational scenarios.

XIII. The riser should have the following:

current meter; riser inclination measurement

devices along the riser; riser tensioning system with an

anti-recoil system to prevent riser damage during disconnection;

flex joint wear bushing to reduce excessive flex joint wear.

riser fill-up valve.

XIV. Parameters that affect the stress situation of the riser should be systematically and frequently collected and assessed to provide an optimum rig position that minimizes the effects of static and dynamic loads.

XV. Wellhead and riser connector should be

equipped with hydrate seal.

XVI. During drilling operations, to avoid any damage to drilling equipment in the event of station keeping failure, there should be prescribed emergency disconnect procedures, clearly indicating the point at which disconnect action is to be started.

XVII. In general, preparation for disconnect should begin at a distance with reference to well mouth, when it is 2.5 % of water depth and disconnect should be initiated at 5.5 % of water depth.

XVIII. Emergency disconnect should include the following:

i. Hang up of the drill pipes on pipe

rams. ii. Shearing the drill pipe. iii. Effect seal on the wellbore. iv. Disconnect the LMRP. v. Clear the BOP with LMRP. vi. Safely capture the riser.

XIX. For monitoring riser angles, flex joint

angle reading should be available at the driller console on a real time basis and connected to an alarm on derrick floor.

XX. In variance to 0.5 ppg kick margin

normally considered, for deep water a variance of upto 0 .2 ppg for conductor casing interval and 0.3 ppg for surface casing interval can be considered.

XXI. When using tapered drill pipe string

there should be pipe rams to fit each pipe size. Variable bore rams should have sufficient hang off load capacity.

XXII. Bending loads on the BOP flanges

and connector shall be verified to withstand maximum bending loads (e.g. highest allowable riser angle and highest expected drilling fluid density.)

6.5 Choke and Kill Lines 6.5.1 Choke Lines and Choke Manifold

Installation with Surface BOP

I. The choke manifold consists of high pressure pipe, fittings, flanges, valves, and manual and/or hydraulic operated adjustable chokes. This manifold may bleed off wellbore pressure at a controlled rate or may stop fluid flow

11

from the wellbore completely, as required.

II. For working pressure of 3000 psi and

above, flanged, welded or clamped connections should be used on the component subjected to well pressure.

III. Choke line from BOP to choke

manifold and bleeding line should be of minimum 3 inches nominal diameter.

IV. In down stream of choke line alternate

flow and flare routes should be provided so that eroded / plugged or malfunctioning parts can be isolated for repair without interrupting flow control.

V. When buffer tanks are employed in

down stream of chokes, provision should be made to isolate a failure or malfunctioning without interrupting flow.

VI. The choke manifold should be placed

in a readily accessible location, preferably outside of the rig structure.

VII. All the choke manifold valves should

be full opening and designed to operate in high pressure gas and drilling fluid service.

VIII. All the connections and valves in the

upstream of choke should have a working pressure at least equal to the rated working pressure of ram preventer in use.

IX. Choke manifold should be pressure tested as per the schedule as fixed for blowout preventer stack in use.

X. The spare parts for equipment subject

to wear or damage should be readily available.

XI. Pressure gauges and sensors

compatible to drilling fluid should be installed so that drill pipe and annular pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted. These should be tested / calibrated as per documented schedule.

XII. Preventive maintenance of the choke assembly and controls should be performed regularly, checking particularly for corrosion, wear and plugged or damaged lines.

XIII. Spare parts requirement as per OEM

should be considered. However, minimum spare parts as listed below should be readily available:

i. One complete valve for each

size installed. ii. Two repair kits for each valve

size installed. iii. Parts for manually adjustable

chokes, such as flow tips, seat and gate, inserts, packing, gaskets, O-rings, disc assemblies, and wear sleeves.

iv. Parts for remotely controlled choke(s).

v. Miscellaneous items such as hose, flexible tubing, electrical cable, pressure gauges, small control line valves, fittings and electrical components.

XIV. The following are the

recommendations for choke installation upto 5000 psi WP rating:

i. Use two manually operated

adjustable chokes (out of two chokes, use of one remotely operated choke is optional).

ii. At least one valve should be installed in upstream of each choke in the manifold.

XV. The following are the

recommendations for choke installation of 10000 psi WP and above rating:

i. One manually operated

adjustable choke and at least one remotely operated choke should be installed. If prolonged use of this choke is anticipated, a second remotely operated choke should be used.

ii. Two valves should be installed in upstream of each choke in the manifold.

iii. The remotely operated choke should be equipped with an emergency backup system such as a manual pump or nitrogen

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for use in the event rig air becomes unavailable.

6.5.2 Kill Lines and Kill Manifold

Installation with Surface BOP

I. The kill line system provides a means of pumping into the wellbore when the normal method of circulating down through the Kelly or drill pipe cannot be employed. The kill line connects the drilling fluid pumps to a side outlet on the BOP stack.

II. All lines valves, check valves and flow

fittings should have a working pressure at least equal to the rated working pressure of the ram BOPs in use. The equipment should be tested on installation and periodic operation, inspection; testing and maintenance should be performed as per the schedule fixed for the BOP stack in use, unless OEMs recommendations dictate otherwise.

III. Line size should be minimum 2 inches

nominal diameter.

IV. Two full bore valves (manual / HCR) should be installed for up to 3000 psi manifold. Use of check valve is optional.

V. Two full bore manual valves and a

check valve or one full bore manual and one HCR valve should be used in kill line in 5000 psi and above pressure rating manifold.

VI. Spare parts requirement as per OEM

should be considered. However, minimum spare parts as listed below should be readily available:

i. One complete valve for each

size installed. ii. Two repair kits for each valve

size utilised. iii. Miscellaneous items such as

hose, flexible tubing, electrical cable, pressure gauges etc.

6.5.3 Choke and Kill Lines Installation

with Subsea BOP Stack

I. Subsea BOP choke and kill lines are connected through choke manifold to

permit pumping or flowing through either line.

II. Choke and kill line should be of

minimum three inches nominal diameter.

III. One kill / choke line should be

connected to lower most side outlet of BOP.

IV. There should be minimum one choke

line and one kill line connection above lower ram BOP.

V. The ram BOP outlet connected to

choke or kill line should have two full opening hydraulically operated fail-safe-close valves adjacent to preventer.

VI. Connector pressure sealing elements

should be inspected, changed as required, and tested before being placed in service. Periodic pressure testing is recommended during installation. Pressure rating of all lines and sealing elements should be at least equal to the rating of ram BOP.

VII. Periodic flushing of choke and kill line

should be carried out to avoid plugging since they are normally closed.

VIII. Flexible connections required for

choke and kill lines should have pressure rating at least equal to the rated working pressure of ram BOP.

IX. Spare parts requirement as per OEM

should be considered. However, minimum spare parts as listed below should be readily available:

i. One complete valve of each

size installed. ii. Two repair kits for each valve

size in use. iii. Sealing elements for choke

and kill lines. 6.6 Wellhead, BOP Equipment and

Choke & Kill Lines Installation

I. Wellhead equipment should withstand anticipated surface pressures and allow for future remedial operations. Wellhead should be tested on installation.

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II. Prior to drilling out the casing shoe,

the casing should be pressure tested. Pressure test of all casing strings including production casing / liner should be done to ensure integrity of casing.

III. When the well head and BOP stack

used are of higher working pressure than the required as per design of the specific well, the equipment may not be tested to its rated pressure.

IV. When ram type preventers are

installed the side outlets should be below the rams.

V. All connections, valves, fittings, piping

etc. exposed to well pressure, should be flanged or clamped or welded and must have a minimum working pressure equal to the rated working pressure of the preventers.

VI. Always install new and clean API ring

gaskets. Check for any damage in the ring as well as grooves before use.

VII. Correct size bolts/nuts and fittings

should be used and tightened to the recommended torque. All connections should be pressure tested before drilling is resumed.

VIII. All manually operated valves should

be equipped with hand wheels, and always be kept ready for use.

IX. Ram type preventers should have

locking arrangement manual or auto lock.

X. Wellhead side-outlets should not be

used for killing purpose, except in case of emergencies.

XI. Kill lines should not be used for

routine fill up operations.

XII. All sharp bends in high pressure lines should be of targeted type.

XIII. All choke and kill lines should be as

straight as practicable and firmly anchored to prevent excessive whip or vibration. Choke and Kill manifolds should also be anchored.

XIV. All control valves of BOP control unit be either in the fully close or open position as required and should not be left in block or neutral position during operations.

XV. Control valve of blind / blindshear

ram should be protected to avoid unintentional operation from the remote panel.

XVI. Recommended oil level should be

maintained in the control unit reservoir. XVII. Outlets of all sections of well head

should have at least one gate valve. 6.7 Blow out Preventer Testing

6.7.1 Function Test

I. All operational components of the BOP equipment systems and diverter (if in use) should be function tested at least once a week to verify the components intended operations.

II. The test should be preferably conducted when the drill string is inside casing.

III. Both pneumatic and electric pump of

accumulator unit should be turned off after recording initial accumulator pressure.

IV. All the blow out preventers and

hydraulically operated remote valve (HCR) in choke / kill line should be function tested. Closing time of rams and opening time of HCR should be recorded.

V. For surface BOP stack closing time

should not exceed 30 seconds for each ram preventers and annular preventers smaller than 18" and 45 seconds for annular preventer of 18" and larger size. For sub-sea BOP stack closing time should not exceed 45 seconds for all ram preventers and 60 seconds for annular preventers.

VI. Operating response time for choke and kill valves (either open or close) should not exceed the minimum observed ram BOP close response time.

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VII. Function test should be carried out alternately from main control unit / rig floor panel / auxiliary panel.

VIII. Record final accumulator pressures

after all the functions. It should not be less than 200 psi above the recommended precharge pressure of accumulator bottles.

IX. All the gate valves and blow out

preventers should be returned to their original position before resuming operations.

X. All the results should be recorded in the

prescribed format (Annexure-VII).

6.7.2 Pressure Test

I. All blowout prevention components that may be exposed to well pressure should be tested first to a low pressure and then to a high pressure. These include blowout preventer stack, all choke manifold components, upstream of chokes, kill manifold / valves, kelly valves, drill pipe and tubing safety valves and drilling spools (if in use). Pressure test (both low and high) on each component should be of minimum 5 minutes duration, each. All the results should be recorded in the format. (Annexure - VIII)

II. Test BOP using cup tester or test plug.

III. Before pressure testing of BOP stack,

choke and kill manifold should be flushed with clean water.

IV. Clean water should be used as test

fluid. However for high pressure gas wells, use of inert gas such as N2 (nitrogen) as test fluid is desirable.

V. High pressure testing unit with pressure

chart recorder be used for pressure testing.

VI. Use test stump for sub-sea BOP stack

pressure testing. VII. Well control equipment should be

pressure tested:

a. When installed. b. After setting each casing string.

c. Following repairs that require breaking a pressure connection.

d. But not less than once every 21 days.

VIII. Low pressure test should be carried out

at 200-300 psi. IX. Once the equipment passes the low

pressure test, it should be tested to high pressure.

X. Initial pressure test of blowout preventer

stack, manifold, valves etc., should be carried out at the rated working pressure of the preventer stack or well- head whichever is lower. Initial pressure test is defined as those tests that should be performed on location before the well is spudded or before the equipment is put into operational service.

XI. Subsequent high pressure tests should

be carried out at a pressure greater than maximum anticipated surface pressure. Exception is the annular preventer which should be tested to 70% of its rated pressure or maximum anticipated surface pressure whichever is lower.

XII. The pipe used for testing should be of

sufficient weight and grade to safely withstand tensile, yield, collapse, or internal pressures.

XIII. Precaution should be taken not to

expose the casing to pressures in excess of its rated strength. A means should be provided to prevent pressure build up on the casing in the event the test tool leaks (wellhead valve should be kept open when pressure testing with test plug).

XIV. Pressure should be applied from the

direction in which all the BOPs, choke and kill manifold, FOSV / Kelly cock etc. would experience pressure during kick.

6.8 Minimum Requirements for Well

Control Equipment for Workover operations (on land)

For workover operations:

I. BOP stack should have at least one

double or two single ram type preventers - one of which must be

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equipped with correct size pipe/tubing rams and the other with blind or blind-shear ram. Working pressure rating of BOP stack should exceed anticipated surface pressure.

II. Kill line should be of minimum 2 inch

size. III. One independent automatic

accumulator unit with a control manifold, clearly showing open and closed positions, for preventer(s) to be provided. The accumulator capacity should be adequate for closing all the preventers without recharging accumulators. Unit should be located at safe easily accessible place.

IV. The BOP stack should have remote

control panel clearly showing open and closed positions for each preventer. This Control Panel should be located near to the drillers position.

V. Trip tank should be installed on

workover rig deployed for servicing of high pressure/ gas wells for continuous fill up and monitoring the hole during round trips. Indicator to monitor tank level can be either mechanical or digital and clearly visible to driller.

VI. Full opening safety valve of drill string /

tubing size and matching thread connection should always be available at derrick floor during well servicing. It should be kept ready in 'open' position for use with operating wrench. Operating wrench(s) should be kept at a designated place.

VII. Sufficient volume of the workover fluid

should be available in reserve during workover operations.

VIII. During conventional production testing,

well should be perforated with adequate overbalance.

IX. After release of the packer the string

should be reciprocated, to ensure complete retraction of packer elements, prior to pull out of string. It should be ensured that there is no swabbing action.

7.0 Procedures and Techniques for Well Control (Prevention and Control of Kick)

7.1 Kick Indications

Indications of kick can be: I. Increase in drilling fluid return

rate II. Pit gain or loss III. Changes in flowline temperature IV. Drilling breaks V. Pump pressure decease and

pump stroke increase VI. Drilling fluid density reduction VII. Oil show VIII. Gas show

7.2 Prevention and Control of Kick

In case of overbalance drilling:

I. The planned drilling safety margin is difference between planned drilling fluid weight and estimated pore pressure.

II. To maintain primary well control,

drilling personnel should ensure that the hydrostatic pressure in the wellbore is always greater than the formation pressure by safety margin.

III. The use of trip margin (which is in

addition to safety margin) is encouraged to offset the effects of swabbing and equivalent circulating density (ECD). The additional hydrostatic pressure will permit some degree of swabbing without losing primary well control.

IV. Successful well control (Blowout

prevention programme) includes following elements:

a. Training of personnel and

drills. b. Monitoring and maintaining

drilling fluid system. c. Selection of appropriate well

control equipment. d. Installation, maintenance and

testing of well control equipment.

e. Adoption of established well control procedures.

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7.2.1 Precautions before Tripping Out

I. Conditioning of drilling fluid prior to tripping out should be ensured. This should include: a. No indication of influx of

formation fluids. b. The drilling fluid density in and out

should not differ more than 0.024 gm/cc (0.2 ppg.) in open hole. In cased hole there should not be any difference.

II. A trip tank shall be lined up and

function tested. Trip sheet shall be ready to be filled during tripping out (Annexure-VI).

III. Full opening safety valve(s) with

suitable working pressure and with proper connections and size, to fit all drill string connections, must be available on the rig floor. They should be kept ready in 'open' position for use with operating wrench. Operating wrench(s) should be kept at a designated place.

IV. An inside BOP, drill pipe float valve or

drop in check valve should be available for use whenever stripping is required to be done.

V. As far as possible tripping out should

be dry. If tripping out is wet, proper mud bucket should be used enabling mud to flow back to the return channel.

7.2.2 Precautions During Tripping Out

I. Well should be checked for swabbing during pulling out. If positive, suitable corrective measures such as change in tripping speed, tripping out with pump on, change in drilling fluid properties etc should be taken.

II. Trip tank volume should be monitored

and same should be recorded in the trip sheet (Annexure -VI).

III. If hole is not taking proper amount of

mud (as per trip sheet), stop tripping and conduct flow check to ensure whether the well is self-flowing. If positive, shut the well, record the pressures and circulate out the kick by

suitable well control method. If no self flow is observed, run back to the bottom and circulate and condition the drilling fluid.

IV. Flow checks should be carried out:

i. Prior to all trips out of the

hole. ii. During first 10 stands. iii. At the casing shoes. iv. Prior to tripping out of drill

collars through BOP stack.

V. Any time a trip is interrupted, safety valve should be installed on the drill string.

7.2.3 Precautions During Tripping In

I. Regular flow checks and monitoring of level in annulus should be done. Where situation requires trip tank may be used to monitor drilling fluid loss/gain.

II. Circulation should be given to break

gelation of mud as per requirements especially in deep wells and where heavy mud is used.

III. With a float valve in the string, drill

pipe should be filled up intermittently. 7.2.4 Precautions During Casing

Lowering

I. Regular flow checks and monitoring of level in annulus should be done and fill up schedule of casing pipe / liner should be followed as per the plan and use clean mud for casing/liner filling.

II. Running in speed of casing/liner

should be maintained considering allowable surge pressure.

7.2.5 Pre-kick Planning

I. A plan detailing what actions are to be taken should a kick occur must be available. Plan should consider equipment limitations, casing setting depths, maximum fluid density, pressures that may be encountered, fracture gradients and expected hazards.

17

II. This should also include roles

responsibilities of the personnel during kick.

III. The following information should be

pre-recorded for use in kill sheet preparation: casing data (properties), safe working pressure limit for surface blowout preventer equipment, wellhead, casing string, approved maximum allowable casing pressure (MAASP) and contingency plan, pump rate for killing operation (SCR), system pressure losses, capacities-displacement, mud pump data, drilling fluid mixing capability, trip margin, water depth (offshore), well profile and shut-in method to be used (soft / hard shut in).

IV. Record slow circulating rates at 1/3

and 1/2 the pump speed of drilling SPM at:

a. the beginning of every shift b. any time the mud weight is

changed c. after drilling 500 feet/150 mtrs. of

new hole d. after bit change e. after pump repairs f. after each trip due to change in

BHA, bit nozzle.

V. LOT / PIT after each casing should be known. Whenever LOT / PIT is to be carried out, 2-3 meters of fresh formation should be drilled.

VI. Distance from rotary table to blowout

preventer (s) be noted and sketch displayed in dog house and Toolpusher's office.

VII. Based on the risk assessment of the

well and depending upon the situation, well control method to be used should be selected. Plan and procedures for special situations such as casing pressure reaching maximum allowable annular surface pressure (MAASP) should be available at the installation (contingency plan).

VIII. Shut in method to be used should also

be pre-selected in the kill sheet.

IX. Sufficient quantity of drilling fluid weighting materials and chemicals must be stored to meet any kick situation.

7.3 Kick Control Procedures

Following are recommended well control procedures for surface stack and sub-sea.

7.3.1 Surface Stack

For onshore and bottom-supported offshore installations:

A. During Drilling

I. Stop drilling II. Pick up Kelly to position tool joint

III. Stop mud pump. IV. Check for self-flow. V. If positive, proceed further to

close the well by any one of the following procedures (Refer Table-1).

v Soft shut in v Hard shut in

TABLE - 1

Sl. No.

Soft Shut in

Hard Shut in

1. Open hydraulic control valve (HCR valve) / manual valve on choke line.

Close Blow out Preventer. (Preferably Annular Preventer)

2. Close Blowout Preventer. Open HCR/Manual valve on choke line when choke is in fully closed position.

3. Gradually close adjustable /remotely operated choke, monitoring casing pressure.

Allow pressure to stabilise and record SIDPP, SICP and Pit Gain.

4. Allow the pressure to stabilize and record SIDPP, SICP and Pit gain.

-------------

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VI. Monitor the casing pressure. If the casing pressure is about to exceed MAASP, follow the contingency plan.

VII. Calculate the drilling fluid density required to kill the kick.

VIII. Initiate the approved / selected well

kill method.

IX. Check rig crew duties and stations.

X. Review and update the well control worksheet.

XI. Check pressures of all annuli of the

well.

B. During Tripping

During tripping whenever flow is observed: I. Position tool joint above rotary table

and set pipe on slips.

II. Install Full Opening Safety Valve (FOSV) in open position on the drill pipe and close it.

III. Close the well following any one of the

procedures as per above table. (table - 1)

IV. Monitor the casing pressure. If the

casing pressure is about to exceed MAASP, follow the contingency plan.

V. Calculate the drilling fluid density

required to kill the kick.

VI. Initiate the approved / selected well kill method.

VII. Check rig crew duties and stations.

VIII. Review and update the well control

worksheet.

IX. Check pressures of all annuli of the well.

C. When String is out of Hole I. Close blind / blind-shear ram.

II. Record shut in pressure. III. Monitor the casing pressure. If the

casing pressure is about to exceed maximum allowed (MAASP), follow the contingency plan.

IV. Calculate the drilling fluid density to kill

the kick. V. Initiate the approved /selected well kill

method.

VI. Check rig crew duties and stations.

VII. Review and update the well control worksheet.

VIII. Check pressures on all annuli of the

well.

7.3.2 Floating Installations (Sub Sea)

A. During Drilling

I. Stop drilling II. Position the tool joint for the BOPs

operation.

III. Shut down the drilling fluid pump(s).

IV. Check the well for flow if it is flowing, follow shut in procedure.

V. If the soft shut-in procedure has been

selected: open the choke line, close Annular BOP and close the choke.

VI. If the hard shut-in procedure has been

selected: close Annular BOP and open the choke line with the choke in closed position.

VII. Observe the casing pressure, if it

exceeds MAASP, follow the contingency plan.

VIII. Check for trapped gas pressure. IX. For release of trapped gas, close the

uppermost rams below the choke line and close the diverter, open the annular preventer to allow trapped gas

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to rise, displace riser with kill fluid and close the annular preventer, reopen the ram preventer.

X. Adjust the closing pressure on the

annular preventer to allow stripping of tool joints.

XI. Hang off the drill pipe as follows:

a. With a motion compensator:

i. Position a tool joint above the

hang-off rams leaving the lower Kelly cock high enough above the floor to be accessible during the maximum expected heave and tide when the selected tool joint rests on the hang-off rams.

ii. Close the hang-off rams.

iii. Carefully lower the drill string until

the tool joint rests on the hang-off rams.

iv. Reduce support pressure on the

motion compensator to support about half of the weight of drill string above the BOPs plus some overpull to provide drill string tension to assist shearing, if required.

b. Without a motion

compensator:

i. Set the slips on the top joint of drill pipe.

ii. Close the lower Kelly cock.

iii. Break the Kelly/top drive

connection above the lower Kelly cock and put it in the rat hole.

iv. Pick up the assembled space-out

joint, safety valve, and circulating head with the safety valve closed. Make up the space-out joint on the closed lower Kelly cock.

v. Open the lower Kelly cock,

remove the slips, and position tool joint above the hang-off rams leaving the safety valve high enough above the floor to be accessible during the maximum expected heave and tide when the

selected joint rests on the hang-off rams.

vi. Close the hang-off rams.

vii. Carefully lower the drill string until

the tool joint lands on the closed hang-off rams. Slack off the entire weight of drill string while holding tension on the circulating head with a tension device.

viii. Connect the circulating head to

the standpipe, open the safety valve.

XII. Allow the shut-in pressure to stabilise

and record pressures.

XIII. Determine the volume of the kick.

XIV. Calculate the drilling fluid density required to kill the kick.

XV. Select a kill method. XVI. Check rig crew duties and stations.

XVII. Review and update well control

worksheet.

XVIII. Inspect the BOP stack with television, if feasible.

B. During Tripping I. Install safety valve.

II. Position the tool joint for the BOPs

operation. III. Check the well for flow if it is flowing,

follow shut in procedure. IV. If the soft shut-in procedure has been

selected: open the choke line, close Annular BOP and close the choke.

V. If the hard shut-in procedure has been

selected: close Annular BOP and open the choke line with the choke in closed position.

VI. Observe the casing pressure, if it

exceeds MAASP, follow the contingency plan.

VII. Check for trapped gas pressure.

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VIII. For release of trapped gas, close the uppermost rams below the choke line and close the diverter, open the annular preventer to allow trapped gas to rise, displace riser with kill fluid and close the annular preventer, reopen the ram preventer.

IX. Adjust the closing pressure on the

annular preventer to allow stripping of tool joints.

X. Hang off the drill pipe as follows:

a. With a motion compensator:

i. Position a tool joint above the hang-off rams leaving the safety valve high enough above the floor to be accessible during the maximum expected heave and tide when the selected tool joint rests on the hang-off rams.

ii. Close the hang-off rams. iii. Carefully lower the drill string until

the tool joint rests on the hang-off rams.

iv. Reduce support pressure on the

motion compensator to support about half of the weight of drill string above the BOPs plus some overpull to provide drill string tension to assist shearing, if required.

b. Without a motion compensator:

i. Pick up the assembled space-out joint, safety valve, and circulating head with the safety valve closed. Make up the space-out joint on the string.

ii. Open the safety valve, remove the slips, and position tool joint above the hang-off rams leaving the safety valve high enough above the floor to be accessible during the maximum expected heave and tide when the selected joint rests on the hang-off rams.

iii. Close the hang-off rams.

iv. Carefully lower the drill string until

the tool joint lands on the closed hang-off rams. Slack off the entire weight of drill string while holding

tension on the circulating head with a tension device.

v. Connect the circulating head to

the standpipe, open the safety valve.

XI. Allow the shut-in pressure to

stablise and record pressures.

XII. Determine the volume of the kick.

XIII. Calculate the drilling fluid density required to kill the kick.

XIV. Select a kill method.

XV. Check rig crew duties and stations.

XVI. Review and update well control

worksheet.

XVII. Inspect the BOP stack with television, if feasible.

C. When String is Out of Hole

I. At the first indication of the well

flowing, close the blind / blind-shear rams.

II. Open the gate valve on the subsea

BOP stack to open the choke line, close the choke line at the surface.

III. Record shut-in pressures. Wt.

(specific gravity) of fluid in the choke line should be considered for calculating shut-in casing pressure.

IV. Record the kick volume. V. Run the drill string in the hole to the

top of the BOPs with NRV. VI. Add the hydrostatic pressure of the

fluid in the choke line to the surface pressure to determine the pressure below the blind rams.

VII. Determine if the pressure below the

blind rams can be overbalanced by hydrostatic pressure of the drilling fluid that can be safely contained by the riser. If so, adjust the riser tensioners to support the additional drilling fluid weight and displace the drilling fluid in

21

the riser with drilling fluid of the required density.

VIII. Close the diverter. Open the BOPs

and watch for flow. If the well does not flow, open the diverter and trip in the hole.

IX. If the well starts to flow, close the blind

ram preventer, displace the choke and kill lines with heavy drilling fluid, and circulate until the riser contains drilling fluid of the desired density.

X. Continue going in the hole. Stop

periodically, close the pipe rams, and circulate the riser by pumping down the kill line to maintain the required drilling fluid density in the riser.

After well killing and before resuming

normal operations, density of drilling fluid should be reviewed to include trip margin above kill mud weight.

8.0 Drills and Training

I. The competence with which drilling personnel respond to well control situations and follow correct procedures can be improved by carrying out emergency drills.

II. While drilling in H2S / sour gas prone

area, detectors shall be installed and breathing apparatus in sufficient quantity and cascade system shall be made available. Crew shall be trained to handle situations in this environment.

III. Organisation should assign specific

responsibilities to the identified / designated persons, for actions required during an emergency related to well control, which would be part of rig ERP.

a. Following drills should be

performed: i. Pit drill ii. Trip drill

b. To conduct drill, a kick should

be simulated by manipulating primary kick indicator such as the pit level indicator or the flow line indicator by raising its float gradually and checking for the alarm.

c. The reaction time from float raising to the designated crew member's readiness to start the closing procedure should be recorded and response time should not be more than 60 seconds.

d. Total time taken to complete

the drill should be recorded and it should not be more than 2 minutes.

e. Drill should be initiated without

prior warning during routine operation.

f. Drill should be conducted

once a week with each crew.

g. Drill should be initiated at unscheduled times when operations and hole condition permits.

8.1 Pit Drill (On bottom)

I. Raise alarm by raising mud tank float -automatic or oral.

II. Stop drilling / other operation in

progress. III. Position tool joint for BOPs ram closing.

IV. Stop mud pump V. Secure brake

VI. During / after the above steps, as

applicable, designated crew should move to assigned positions

VII. Check for self flow VIII. Record the response time.

Trip Drill (Drill Pipe in BOP)

I. Give signal by raising alarm.

II. Position tool joint above rotary and set the pipe on slips

III. Install full opening safety valve in open

position.

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IV. Close FOSV after installation V. Designated crew members should move

to assigned position, during / after the above steps, as applicable.

VI. Close BOP VII. Record response time. Note: Trip drill should be carried out preferably when bit is inside the casing. A full opening safety valve for each size and type of connection in the string shall be available on derrick floor, in open position. Safety valves may be clearly marked for size and connection. Trip Drill (Collar in Blowout Preventer)

I. Give signal by raising alarm.

II. Position upper drill collar box at rotary table and set it on slips.

III. Connect a drill pipe joint or stand of drill

pipe on drill collar tool joint with change over sub and position drill pipe in BOP.

IV. Install FOSV in open position. V. Close FOSV.

VI. Close BOP. VII. Record response time. Note: Under actual kick conditions (other

than drills) if only one stand of drill collar remains in the hole it would be probably faster to simply pull the last stand and close the blind ram. If numbers of drill collar stands are more and well condition does not permit step III than install FOSV with change over sub on drill collar, close it and close annular preventer.

Preparation for step III above should be done in advance prior to starting pull out of drill collar - make one single / stand of drill pipe with drill collar change over sub.

Trip Drill (String is out of Hole )

I. Give signal by raising alarm.

II. Close blind/ blind-shear ram.

III. Record response time.

Well Control Training Asstt. Shift Incharge / Asstt. Driller and above supervisory personnel should have valid accredited well control certificate (of the appropriate level). At least one trained person should always be present on derrick floor to observe well for any activity even during shutdown period 9.0 Monitoring System 9.1 Instrumentation Systems

I. Driller's console should have gauges and meters including drillo-meter, SPM meters, pump pressure gauge, rotary torque. The Record-o-graph should record parameters like weight, SPM, pump pressure, rotary torque, rate of penetration. Drillers console should be positioned in such a way that driller can see all the gauges without any obstruction.

II. Flow rate sensor should be installed for

monitoring return mud flow with high / low alarms.

III. Mud / pit volume totaliser should be

installed for all the reserve and active mud tanks to detect mud tank level's deviation with an accuracy of + one barrel. Mud volume totaliser should have high / low alarm (visual or audible setting).

IV. Gas detector should always be

available. Gas measurement should be carried out near the point where the mud from the well mouth surfaces (Shale shaker and rig sub structure).

9.2 Trip Tank System

I. On a drilling rig, the trip tank shall always be in operation during tripping operation, particularly during pulling out operation, for early detection of a kick.

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II. The primary purpose of the trip tank is to measure the amount of drilling fluid required to fill the hole while pulling pipe to determine if the drilling fluid volume matches pipe displacement.

III. A trip tank is a low-volume calibrated

tank which can be isolated from the remainder of the surface drilling fluid system and used to accurately monitor the amount of fluid going into or coming out from the well. A trip tank should be calibrated accurately and should have means for reading the volume contained in the tank at any liquid level. The readout may be direct or remote, preferably both. The size of the tank and readout arrangement should be such that volume changes in the order of can be easily detected.

9.3 Mud Gas Separator (MGS)

Atmospheric Mud Gas Separator should be installed. Liquid seal should be maintained to prevent gas blow through shale shaker. Vent line should be away from derrick floor. The rig maintenance and inspection schedule should provide for periodic non-destructive examination of the mud gas separator to verify pressure integrity. This examination may be performed by hydrostatic, ultrasonic, or other examination methods.

9.4 Degasser

A degasser should be used to remove entrained gas bubbles in the drilling fluid that are too small to be removed by the mud gas separator. Most degassers use some degree of vacuum to assist in removing the entrained gas. All flare lines should be as long as practical with provision of flaring during varying wind directions. Flare lines should be straight as far as possible and should be securely anchored. Degasser should be function tested at least once a week

10.0 Under Balanced Drilling Primary well control during Under Balanced Drilling (UBD) is maintained by flow and pressure control. The bottomhole pressure and the reservoir influx is monitored and controlled by means of a closed loop surface system. This system includes rotating control device (RCD), flowline, emergency shutdown valve (ESDV), choke manifold and surface separation system. The following are the recommended equipment for UBD operations:

I. The RCD shall be installed above the drilling BOP and shall be capable of sealing the maximum expected wellhead circulating pressure against the rotating work string and containing the maximum expected shut-in wellhead pressure against a stationary work string. The RCD is a drill through device with a rotating seal that is designed to contact and seal against the work string (drill string, casing, completion string, etc.) for the purpose of controlling the pressure and fluid flow to surface. Its function is to contain fluids in the wellbore and divert flow from the wellbore to the surface fluids handling equipment during underbalanced operations (drilling, tripping and running completion equipment).

II. The return flowline shall have two

valves, one of which shall be remotely operated and fail-safe-close (ESDV). The flowline and the valves shall have a working pressure equal to or greater than the anticipated shut-in wellhead pressure. At least one valve should be installed in the diverter/flow line immediately adjacent to the BOP stack.

III. A dedicated UBD choke manifold shall

be used to control the flow rate and wellbore pressure, and reduce the pressure at surface to acceptable levels before entering the separation equipment. The choke manifold shall have a working pressure equal to or greater than the anticipated shut-in wellhead pressure. The choke manifold should have two chokes and isolation valves for each choke and

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flow path. Applied surface backpressure should be kept to a minimum to reduce erosion of chokes and other surface equipment.

IV. A surface separation system shall be

selected and dimensioned to handle the anticipated fluid/solids in the return flow. Plugging, erosion or wash-outs of surface equipment should not impact the ability to maintain primary well control.

V. The drill pipe and casing should be

designed for exposure to hydrogen sulphide (H2S) gas.

VI. The BOP stack, flow / diverter line, and bleed off and kill lines should be designed for exposure to H2S in accordance with NACE (MR 075) / ISO 15156 specifications.

VII. Blind-shear rams should be

considered for underbalanced drilling of wells with high Hydrogen Sulphide (H2S) potential.

VIII. A stab-in safety valve for the string in

use should be available on the rig floor.

10.1 Procedures for UBD

I. Procedures for UBD operations should be developed based on risk analysis and risk assessments. These procedures should include:

i. Kicking of the well ii. Making connections iii. Live well tripping iv. Trapped pressure in equipment.

II. When running a work string under balanced, two NRVs, shall be installed in the string, as deep in the work string as practical and as close together as possible. The NRVs should prevent wellbore fluids from entering into the work string. Installation of additional NRVs should be considered depending on the nature of the operation (ie high-pressure gas). The NRV should have a minimum working pressure rating equal to the maximum expected BHP.

III. Snubbing facilities should be used or

the well should be killed with a kill weight fluid prior to tripping pipe, if the

shut-in or flowing wellhead pressure can produce a pipe light condition and a downhole isolation valve (DIV), a retrievable packer system or similar shut-in device, is not in use or is not functioning as designed. The DIV is a full-opening drill through valve, installed down-hole as an integral part of a casing / liner string, at a depth either below the maximum pipe light depth for the work string being tripped in the underbalanced operation (drill string, casing, completion string, etc.) or at a depth that allows the maximum length of BHA, slotted liner or sand screen required to be safely deployed, without having to snubin or kill the well prior to deployment. DIV should have working pressure rating of more than maximum expected differential pressure after closure.

IV. Sufficient kill fluid of required density

should be available on site at any time to enable killing of the well in an emergency.

V. While still in the design stage, a meeting

including all key personnel should be held to discuss the proposed operation so that everyone clearly understands their responsibilities with respect to safety. A key element in planning a safe operation is the site layout. The following considerations should be made when designing the well-site layout:

i. Prevailing winds ii. Access to fluids handling

equipment iii. Equipment placement iv. High pressure line placement

VI. At no time the well should be left open

to the rig floor when the well is live. VII. Trapped gas below the float should be

removed safely before removing the float from the drill string during pulling out.

VIII. If a well is killed prior to tripping,

traditional tripping procedures including the completion of trip sheets should be followed.

IX. Round the clock supervision by

competent persons should be ensured. All personnel involved in operations

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should be trained in UBD operations, and training should be documented.

X. The Well Site Supervisor should have

valid accredited well control certificate for underbalanced drilling and well intervention operations.

XI. Appropriate PPE should be used by all

personnel on the site. XII. A site-specific emergency contingency

plan should be prepared to a level of complexity that the operation warrants, prior to any underbalanced drilling taking place.

XIII. The following table describes incident

scenarios for which well control action procedures should be available (as applicable) to deal with the incidents should they occur (This list is not exhaustive; additional scenarios may be applied based on the actual planned activity):

i. Bottomhole or surface pressure

and / or flow rates detected which could lead to the pressure rating of the rotating control device (static or dynamic) or the capacity of the surface separation equipment being exceeded.

ii. NRV failure, influx into work

string during making connection or tripping in live well.

iii. Leaking connection below

drilling BOP. iv. Leaking rotating control device

or flowline before ESDV, seal elements, connection to flowline, drilling BOP or high pressure riser.

v. Erosion or wash out of choke.

Consider the case where isolation for repair of the choke cannot be achieved.

vi. Failure of surface equipment

after RCD. This can be leaks or plugged equipment and lines.

vii. Work string failure. viii. Emergency shut-in.

ix. Emergency well kill. x. Lost circulation. xi. H2S in the well.

XIV. When hydrocarbons are being

produced or when they are used in the drilling fluid, supplementary fire fighting equipment should be considered. This may require as little as additional hand-held fire extinguishers to as much as having a fire fighting vehicle on-site.

XV. Regardless of the concentration of H2S,

no sour gas may be released to atmosphere at any time.

XVI. Produced fluids containing H2S or

drilling fluids contaminated with H2S should not be stored in open tanks.

XVII. The flare stack shall be as per

regulatory requirements. XVIII. If H2S is expected to be encountered

in the well, a monitoring program shall be in place. As a minimum, monitoring stations should include the rig floor, inside the rig substructure adjacent to the BOPs, and near separation vessels and storage or circulating t