WELL CONTROL OISD RP 174

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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 7 th Floor, New Delhi House, 27, Barakhamba Road, New Delhi 110 001. www.oisd.gov.in II

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. III

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, 7 th Floor, New Delhi House, 27, Barakhamba Road, New Delhi -110 001. Email: oisd@vsnl.com IV

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 ---------------------------------------------------------------------------------------------------------------------------- V

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 Shri R.K. Rajkhowa Shri S.K. Ahuja Shri B.S. Saini Shri A.J. Phukan Oil and Natural Gas Corporation Ltd., Ahmedabad. Oil India Ltd., Duliajan, Assam. Oil and Natural Gas Corporation Ltd., Mumbai. Oil and Natural Gas Corporation Ltd., Sibsagar, Assam. Oil India Ltd., Duliajan, Assam. MEMBER COORDINATOR Shri H.C.Taneja Oil Industry Safety Directorate, New Delhi. VI

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 VII

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 1

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 pipe s 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/cm 2 In term of pressure gradient - psi /ft or kg/cm 2 /meter. 2

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 Swabbing, Loss of circulation Insufficient drilling fluid density. V. Gas cut drilling fluid 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. 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. 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 tophole 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 equipment s design pressure, etc., e.g. marine riser. The diverter system should be accordingly designed. To minimise back pressure (as much as practical) on the wellbore while diverting well fluids, diverter piping should be adequately sized. 3

Vent lines should be 10 or above for offshore and 8 or above for onshore. 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. Diverter valves should be full opening type either pneumatic or hydraulic with automatic sequencing / manual sequencing. I. Stop drilling Pick up Kelly until tool joint is above rotary. Open vent line towards downward wind direction, close diverter packer and close shale shaker inlet valve. 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. V 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. V Monitor and adjust packer pressure as and when required. Alert the personnel on the rig. V IX. 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. 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. V 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. Watch for gas bubbles in the vicinity of drilling vessel. X. Size of the hydraulic control lines should be as per manufacturer s recommendations. XI. X X Control systems of diverter should be capable of closing the diverter within maximum 45 seconds and simultaneously opening the valves in the diverter lines. 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. 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: 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. Welded, flanged or hub end connections are only recommended on all pressure systems above 3000 psi. In sour gas areas H 2 S trim (refer NACE MR0175 / ISO 15156) equipment should be used. Kill lines should be of minimum 2 nominal size and choke line should be of minimum 3 nominal size. 4

V. Size of choke line and choke manifold should be same. V V Closing systems of surface BOPs should be capable of closing each ram preventer and annular preventer up to 18¾ size within 30 seconds and annular preventer above 18¾ size within 45 seconds. Closing systems of sub-sea BOPs should be capable of closing each ram preventer within 45 seconds and annular preventer within 60 seconds. 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 OEM s recommendations. 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 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. Major inspection: after every 5 years of service or as per OEM s recommendation. The BOP stack, choke manifold, and diverter assembly should be disassembled, and inspected in accordance with the OEM s guidelines. V. Spare parts requirement as per OEM should be considered. However, minimum spare parts as listed below should be readily available: V V IX. 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. 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 manufacturer s recommendations. System should be in place to control use of rubber / elastomer parts, having limited shelf life. Separate maintenance history / log book of all the BOPs, Choke manifold and Control unit should be maintained. 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: 5

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 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 blindshear rams. 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. A suitable control fluid should be selected as the system operating medium based on the control system operating requirements, environmental requirements and user preference. 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. 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. 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 Bottomsupported Offshore Installations) 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. 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. 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. 6

V V IX. The hydraulic fluid reservoir should have a capacity equal to at least twice the useable hydraulic fluid capacity of the accumulator system. 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). 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 X office for BOP stack functions, besides the one near the driller. 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. 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: 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. I. Close in on the drill string and on the casing or liner and allow circulation. Close and seal on open hole and allow volumetric well control operations. Strip the drill string using the annular BOP(s). 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. Disconnect the riser from the BOP stack. X 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 V V Circulate the well after drill pipe disconnect. Circulate across the BOP stack to remove trapped gas. 7

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 Arrangements for subsea BOP stack at Annexure IV and V should be referred. Annular BOPs are designated as lower annular and upper annular. Annular BOP may have a lower rated working pressure than the ram BOPs. 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. 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. 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. 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. 8

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. V The remote panels should be connected to the control manifold in such a way that all functions can be operated independently from each panel. X X XV. If diverter control system is not self contained, hydraulic power may be supplied from BOP control system. The diverter control system should be designed to prohibit closing the diverter packer unless diverting lines have been opened. 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. V IX. 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. 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. X 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. 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. X 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. Use of two blind-shear rams is preferred for ensuring the backup seal in case of unplanned disconnect. 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. 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. 9

V V The need to utilize a multiplex BOP control system to meet the closing time requirements should be evaluated for application, if required. The kill-/choke line ID should be verified vis-à-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 (3½ inches). 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. X XV XV 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. 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. Emergency disconnect should include the following: 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 3 rd party. X X A simulated riser disconnect test should be conducted considering manageable emergency weather / operational scenarios. 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. XIX. XX. XXI. XX 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. 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. 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. 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. 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 X XV. 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. Wellhead and riser connector should be equipped with hydrate seal. 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 10

from the wellbore completely, as required. For working pressure of 3000 psi and above, flanged, welded or clamped connections should be used on the component subjected to well pressure. Choke line from BOP to choke manifold and bleeding line should be of minimum 3 inches nominal diameter. 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. V V IX. The choke manifold should be placed in a readily accessible location, preferably outside of the rig structure. All the choke manifold valves should be full opening and designed to operate in high pressure gas and drilling fluid service. 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. 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. X X Preventive maintenance of the choke assembly and controls should be performed regularly, checking particularly for corrosion, wear and plugged or damaged lines. 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. X 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 11

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. 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 OEM s recommendations dictate otherwise. Line size should be minimum 2 inches nominal diameter. 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. permit pumping or flowing through either line. Choke and kill line should be of minimum three inches nominal diameter. One kill / choke line should be connected to lower most side outlet of BOP. 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 failsafe-close valves adjacent to preventer. V V 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. Periodic flushing of choke and kill line should be carried out to avoid plugging since they are normally closed. Flexible connections required for choke and kill lines should have pressure rating at least equal to the rated working pressure of ram BOP. Spare parts requirement as per OEM should be considered. However, minimum spare parts as listed below should be readily available: 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 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 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. 12

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. 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. X XV. X 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. Control valve of blind / blind shear ram should be protected to avoid unintentional operation from the remote panel. Recommended oil level should be maintained in the control unit reservoir. When ram type preventers are installed the side outlets should be below the rams. XV Outlets of all sections of well head should have at least one gate valve. 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. V V IX. Always install new and clean API ring gaskets. Check for any damage in the ring as well as grooves before use. 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. All manually operated valves should be equipped with hand wheels, and always be kept ready for use. 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. X X Kill lines should not be used for routine fill up operations. All sharp bends in high pressure lines should be of targeted type. 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. 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. The test should be preferably conducted when the drill string is inside casing. Both pneumatic and electric pump of accumulator unit should be turned off after recording initial accumulator pressure. 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 18¾" and 45 seconds for annular preventer of 18¾" 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. Operating response time for choke and kill valves (either open or close) should not exceed the minimum observed ram BOP close response time. 13

V V IX. Function test should be carried out alternately from main control unit / rig floor panel / auxiliary panel. Record final accumulator pressures after all the functions. It should not be less than 200 psi above the recommended precharge pressure of accumulator bottles. 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) Test BOP using cup tester or test plug. Before pressure testing of BOP stack, choke and kill manifold should be flushed with clean water. Clean water should be used as test fluid. However for high pressure gas wells, use of inert gas such as N 2 (nitrogen) as test fluid is desirable. V. High pressure testing unit with pressure chart recorder be used for pressure testing. V Use test stump for sub-sea BOP stack pressure testing. Well control equipment should be pressure tested: a. When installed. b. After setting each casing string. V IX. c. Following repairs that require breaking a pressure connection. d. But not less than once every 21 days. Low pressure test should be carried out at 200-300 psi. 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 wellhead 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. X X X 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. The pipe used for testing should be of sufficient weight and grade to safely withstand tensile, yield, collapse, or internal pressures. 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). 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 14

equipped with correct size pipe/tubing rams and the other with blind or blindshear ram. Working pressure rating of BOP stack should exceed anticipated surface pressure. Kill line should be of minimum 2 inch size. 7.0 Procedures and Techniques for Well Control (Prevention and Control of Kick) 7.1 Kick Indications Indications of kick can be: 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. 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 driller s 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. 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. V V IX. Sufficient volume of the workover fluid should be available in reserve during workover operations. During conventional production testing, well should be perforated with adequate overbalance. 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. I. Increase in drilling fluid return rate Pit gain or loss Changes in flowline temperature Drilling breaks V. Pump pressure decease and pump stroke increase Drilling fluid density reduction V Oil show V 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. 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. 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. 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. 15