Well Control OISD RP 174

Transcription

1 Page No. I OISD - RP 174 T h ir d Edition April, 2016 For Restricted Circulation OISD RP 174 Prepared by FUNCTIONAL COMMITTEE FOR REVIEW OF WELL CONTROL OIL INDUSTRY SAFETY DIRECTORATE Government of India Ministry of Petroleum & Natural Gas 8 th Floor, OIDB Bhavan, Plot No. 2, Sector 73, Noida (U.P.) Website: Tele: , Fax:

2 Page No. II 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 8 th Floor, OIDB Bhavan, Plot No. 2, Sector - 73 Noida (U.P.)

3 Page No. III Preamble Indian petroleum industry is the energy lifeline of the nation and its continuous performance is essential for sovereignty and prosperity of the country. As the industry essentially deals with inherently inflammable substances throughout its value chain upstream, midstream and downstream Safety is of paramount importance to this industry as only safe performance at all times can ensure optimum ROI of these national assets and resources including sustainability. While statutory organizations were in place all along to oversee safety aspects of Indian petroleum industry, Oil Industry Safety Directorate (OISD) was set up in 1986 Ministry of Petroleum and Natural Gas, Government of India as a knowledge centre for formulation of constantly updated worldscale standards for design, layout and operation of various equipment, facility and activities involved in this industry. Moreover, OISD was also given responsibility of monitoring implementation status of these standards through safety audits. In more than 25 years of its existence, OISD has developed a rigorous, multi-layer, iterative and participative process of development of standards starting with research by in-house experts and iterating through seeking & validating inputs from all stake-holders operators, designers, national level knowledge authorities and public at large with a feedback loop of constant updation based on ground level experience obtained through audits, incident analysis and environment scanning. The participative process followed in standard formulation has resulted in excellent level of compliance by the industry culminating in a safer environment in the industry. OISD except in the Upstream Petroleum Sector is still a regulatory (and not a statutory) body but that has not affected implementation of the OISD standards. It also goes to prove the old adage that self-regulation is the best regulation. The quality and relevance of OISD standards had been further endorsed by their adoption in various statutory rules of the land. Petroleum industry in India is significantly globalized at present in terms of technology content requiring its operation to keep pace with the relevant world scale standards & practices. This matches the OISD philosophy of continuous improvement keeping pace with the global developments in its target environment. To this end, OISD keeps track of changes through participation as member in large number of International and national level Knowledge Organizations both in the field of standard development and implementation & monitoring in addition to updation of internal knowledge base through continuous research and application surveillance, thereby ensuring that this OISD Standard, along with all other extant ones, remains relevant, updated and effective on a real time basis in the applicable areas. Together we strive to achieve NIL incidents in the entire Hydrocarbon Value Chain. This, besides other issues, calls for total engagement from all levels of the stake holder organizations, which we, at OISD, fervently look forward to. Jai Hind!!! Executive Director Oil Industry Safety Directorate

4 Page No. IV 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. Standardization in design philosophies and operating and maintenance practices at a national level was hardly in existence, this coupled with feedback from some serious accidents that occurred in the recent past in India and abroad, emphasized 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, standardizing and upgrading the existing standards to ensure safe operations. Accordingly OISD c on s t i t ut ed a number of functional committees of experts nominated from the industry to draw up standards and guidelines on various subjects. The recommended practices for "" have been prepared by the Functional Committee for revision of ". 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. 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, Oil Industry Safety Directorate, 8 th Floor, OIDB Bhavan, Plot No. 2, Sector - 73 Noida (U.P.)

5 Page No. V 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 d at a 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.

6 Page No. VI COMMITTEE FOR PREPARING STANDARD ON "WELL CONTROL" Name Designation & Position in Organisation Committee S/Shri.A.K. Hazarika GM(D) Leader ONGC, Mumbai 2. S.L. Arora GM(D) ONGC, Ahmedabad 3. A. Borbora Dy. CE(D) OIL, Duliajan 4. C.S. Verma Dy. CE(D) Oil, Rajasthan 5. A. Verma CE(P) ONGC, Mumbai 6. V.P. Mahawar CE(D) ONGC, Dehradun 7. B.K. Baruah DGM(D) ONGC, ERBC 8. S.K. Ahuja SE(D) ONGC, ERBC Member Member Member Member Member Member Member 9. P.K. Garg Addl. Director (E&P) Co-ordinator

7 Page No. VII 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.

8 Page No. VIII Functional Committee for Complete Review of OISD-RP-174, 2016 LEADER Shri Sunil Upadhyay, BGEPIL MEMBERS Shri Tarsem Singh, Shri Ajay Dixit, Shri Sanjay Bhatt, Shri Krantijyoti Deka, Shri Jagannath Chetia, Oil Industry Safety Directorate ONGC, Ahmedabad ONGC, Mumbai Oil India Limited Oil India Limited COORDINATOR Shri A K Jain, Oil Industry Safety Directorate

9 Contents Page No. IX Section Description Page 1.0 Introduction Scope Definitions Planning for Well Planning Diverter Equipment and Control System Procedures for Diverter Operations Equipment & Control System Selection Periodic Inspection and Maintenance Surface Blow out Prevention Equipment Subsea Blow out Prevention Equipment Choke and Kill Lines Wellhead, BOP Equipment and Choke & Kill Lines Installation Blow out Preventer Testing Minimum Requirements for Equipment for Workover Operations (on land) Procedures and Techniques for (Prevention and Control of Kick) Cause of Kick Cause of Reduction in Hydrostatic Head Kick Indication Prevention and Control of Kick Kick Control Procedure Drills and Training Pit Drill (On bottom) Trip Drill (Drill Pipe in BOP) Trip Drill (Collar in Blowout Preventer) Trip Drill (String is out of Hole) Training Monitoring System Instrumentation Systems Trip Tank System Mud Gas Separator (MGS) Degasser Under Balanced Drilling Procedures for UBD Equipment Arrangement for HTHP Wells References 42 Abbreviations 43 Annexure I to VIII 44-51

10 OISD RP 174 Page No. 1 Sr.Number:OISD/DOC/2016/1 Recommended Practices for 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 casing head 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 Bottom hole 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 OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

11 OISD RP 174 Page No. 2 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 of mud + surface pressure While killing a well BHP = Hydrostatic pressure of mud + annular pressure losses + Surface pressure Running pipe in the hole BHP = Hydrostatic pressure + surge pressure 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 Connection gas A distinct increase in gas above a normal background gas when bottoms up circulation occur after a pipe connection. 3.9 Degasser A vessel which utilizes pressure reduction or inertia to separate entrained gases from the liquid phases 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 ECD ECD i.e. Equivalent Circulating Density is equal to Original drilling or completion fluid density plus annular pressure losses EMW EMW i.e. Equivalent Mud Weight is equal to Original Mud weight + Annular pressure losses in EMW + weight of drilled cuttings existing in the annulus 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 FOSV Full Opening Safety Valve (FOSV) is a ball valve having ID equal to that of drill pipe /tubing Designed for high pressure condition and it can hold pressure from both directions. It is Installed into the top joint of drill pipe or tubing at the rig floor and closed quickly when well kicks. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

12 OISD RP 174 Page No Gate Valve A valve that employs a sliding gate to open or close the flow passage. The valve may or may not be full opening 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) = x mud wt.(ppg) x TVD (feet) Hyd. pressure (kg/cm2) = Mud wt.( gm/cc) x TVD (mtrs)/10 where TVD = True vertical depth Influx The flow of fluids from the formation into the wellbore IBOP Internal Blow out Preventer (IBOP) is a device that can be installed in the drilling string / tubing string and acts as a check valve allowing drilling fluid to be circulated down the string but prevents back flow 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 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 Kill Rate Pressure The circulating pressure measured at the drill pipe gauge when the mud pumps are operating at the kill rate Kill Manifold Kill manifold is an arrangement of high pressure valves, pipelines; check valves which provide a means of pumping fluid into the wellbore when normal circulation down the drill string through Kelly or drill pipe cannot be established Kelly Cock A high pressure valve installed immediately below and above the Kelly that can be closed to confine pressures inside the drill string. It works as a check valve when engaged. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

13 OISD RP 174 Page No Leak Off Test Leak off test is a procedure used to determine the pressure required to initiate a fracture in the open or exposed formation LMRP LMRP (Lower Marine Riser Package) is the upper section of Subsea BOP stack consisting of a hydraulic connector, annular BOP, ball / flex joint, riser adapter, jumper hoses for choke, kill and auxiliary lines and subsea control pods. This interfaces with lower BOP stack 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 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 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 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 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. In term of equivalent mud wt. - ppg or gm/cc 3.31 Riser Margin Riser Margin is the mud weight increase below the mud line to compensate bottom hole pressure in case of an accident, disconnect or a failure in the marine riser close to the BOP stack at sea bed Shell The word shall is used to indicate that the provision is mandatory Should The word should is used to indicate that the provision is recommendatory as per sound engineering practice Trip Gas Trip gas is the accumulated gas which enters the wellbore when the mud pumps are shut and trip is being made Trip Margin Trip margin is the small amount of drilling fluid weight carried over that needed to balance formation pressure to overcome the pressure reduction effects caused by swabbing during tripping operations. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

14 OISD RP 174 Page No Umbilical Umbilical is a bundle of helically of sinusoidal wound small diameter flexible hoses, steel tubes, optical fiber cables or electrical cables. These are connective medium between surface installations and subsea installations and generally provide hydraulic / electrical power, fluid injection and or communication services 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

15 OISD RP 174 Page No Planning for well control 4.1 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,kick tolerance, pore pressure, formation fracture pressure, down hole temperature prediction for the well. b. Cementation details. c. Drilling fluid type and 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. I 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. Riser less drilling (with floater) 5.0 Diverter E q u i p m e n t 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. Diverter system is mandatory for: Subsea wells Exploratory wells onshore as well as offshore. Development wells where shallow gas pockets are expected. 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. I To minimize back pressure (as much as practical) on the wellbore while diverting well fluids, diverter piping should be adequately sized. Vent lines should be 10 or above for offshore and 8 or above for onshore. IV. The diverter and Mud return (flow line) lines should be separate lines. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

16 OISD RP 174 Page No. 7 V. Diverter lines should be straight as far as possible, properly anchored and sloping down to avoid blockage of the lines with cuttings etc. VI. V VI Diverter valves should be full opening type either pneumatic or hydraulic with automatic sequencing / manual sequencing. 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. 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 manufacturer s 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. X XI 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: I. Stop drilling I 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. IIIA. In Offshore installation vent line selector valve is to be kept in 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. V VI Monitor and adjust packer pressure as and when required. Alert the personnel on the rig. 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

17 OISD RP 174 Page No Equipment & C o n t r o l 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 one step lower rating than ram BOP. (Maximum anticipated surface pressure = Maximum anticipated formation pressure). I Welded, flanged or hub end connections are only recommended on all pressure systems above 3000 psi. In sour gas areas H 2S 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. V. Size of choke line and choke manifold should be same. Minimum nominal inside diameter (ID) for downstream of chokes shall be equal to or greater than the nominal connection size of the choke inlet and out let. VI. The BOP control system shall be capable of A) Closing each Ram BOP in 30 seconds or less than 30 seconds B) Closing annular preventers smaller than 18 3/4 in 30 seconds or less and for annular preventers of 18 3/4 in. and larger size, in 45 seconds or less than 45 seconds. C) Closing and opening of choke & kill valves shall not exceed the minimum observed ram close response time. V Closing systems of sub-sea BOPs should be capable of closing each ram preventer within 45 seconds and annular preventer within 60 seconds. VI 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 organization should establish inspection and maintenance procedures for well control equipment s. Inspections and maintenance procedures should take into consideration the OEM s recommendations and / or relevant API / OISD standards. 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 OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

18 OISD RP 174 Page No. 9 General condition of a. Piping systems b. Hoses c. Electric conduit/cords d. Mechanical components e. Structural components f. Filters/Strainers g. Safety covers/devices h. Control system adequacy i. Battery condition I IV. Inspection 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 shell be carried out after every 5 years. Th e B O P s tac k, choke manifold, control unit, diverter assembly shell be disassembled, and inspected in accordance with the OEM s guidelines. The recertification of well control equipment after five yearly major inspections should preferably be carried out by OEM or OEM authorized repair facility or by A) An API 16A approved facility having 16A certification for specific type of BOP. Recertification procedure for BOP shall be as per Annexture B (Requirement for repair and remanufacture of BOP) of API 16A, 2004 edition and for Flange/Hub connection it will be as per API 6A. B) An API 16C & 6A approved facility for choke manifold & its accessories (Refer Product specification clause 4.2 of API 16C, 2 nd edition March 2015 and Annexure J of API 6A 20 th edition 2010 for repair and remanufacture requirement) C) An API 16D approved agency for control unit as per clause number 6 (Periodic maintenance and inspection procedure) of API 16D edition 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 manufacturer s recommendations. V Rubber / elastomer parts, having limited shelf life should be stored in air condition Environment. Elastomers exposed to drilling / completion fluid shall be compatible to fluid in use while drilling and completion operations. VI IX. Separate maintenance history / log book of each of all the BOPs, Choke manifold and Control unit should be maintained. All pressure gauges and relief valves on the BOP control unit and remote panel should be calibrated at least once in a year. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

19 OISD RP 174 Page No 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: a) 2000 psi WP b) 3000 psi WP c) 5000 psi WP d) psi WP e) psi WP, and f) 20,000 psi WP Refer Annexure-I for recommended 2000 psi BOP stack.one single ram type preventers with blind or blind cum shear ram and one annular BOP or one double ram BOP of which one ram should be equipped with correct size pipe rams and the other with blind or blind shear rams. For Offshore rigs one annular BOP and one double ram BOP of which one ram should be equipped with correct size pipe rams and the other with blind or blind shear ram should be used. The Blind cum shear ram shall be capable of shearing drill pipe of any size and grade in the well bore and seal it under maximum anticipated surface pressure. Preferably one Annular preventer and one blind ram preventer should be considered for the following advantages a) It can close on any shape or size of tubular or non-cylindrical objects with minimum response time b) Drill pipe / tool joint can be slipped through it by means of careful control of the hydraulic closing pressure A minimum of one set of blind rams or blind shear rams (BSRs) shall be installed when ram type preventers are to be installed. This requirement shall also apply to 2K or lesser rated working pressure systems and a minimum 2 BOP stack arrangement. A documented risk assessment shall be performed by the operator for all classes of BOP arrangements to identify ram placements and configurations to be installed. This assessment shall include tapered strings, casings completion equipment, test tools. I IV. 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 / / psi BOP stack. The stack comprises of, besides annular BOP, three single, or one double and one single ram type preventers one of which should be equipped with blind or blind-shear rams (For Of f s hore and Ons hore gas w ells Blind shear ram is mandatory in 10 K and above rated BOP stack) and the other two to be fitted with correct size of pipe ram and variable ram to close against pipe if multiple size of string is in use. 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

20 OISD RP 174 Page No. 11 VI. In spite 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. V A fill up line should be provided above the uppermost preventer. VI Prior to commencing operations with tapered drill string, the BOP stack should be provided with one set of variable pipe rams capable of sealing around both the sizes of drill pipes. IX. Full opening safety valve of drill string size and matching thread connection of rated working pressure should always be available at derrick floor. It should be kept ready in 'open' position. Operating wrench to operate FOSV is to be kept in designated place. X. A non-return valve known as check valve of drill string size and matching thread connection of rated working pressure also is to be kept on rig floor in open position and is called IBOP 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. I IV. A suitable control fluid should be selected as the system operating medium based on the control system operating requirements, environmental requirements and user preference. Two (primary and secondary) or more pump systems should be used having independent power sources. Electrical and 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 pressurization by a minimum of two devices. 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. V VI The combined output of all pumps should be capable of charging the entire accumulator system from precharge pressure to the maximum rated working pressure within 15 minutes. 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 adjusted within 100 psi of the recommended precharge pressure during installation and at start of drilling (interval not to exceed 60 days). OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

21 OISD RP 174 Page No. 12 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, HCR valves 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. X XI XIV. The control unit should be installed in a location away from the drill floor and easily accessible to the persons during an emergency. 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- h a z ar d o u s area preferably tool pusher office 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. A. The hydraulic lines system (from control unit to BOP stack) to be pressure tested at maximum operating pressure on installation. B. Accumulator relief valve and manifold relief valve to be tested six-monthly. 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. I IV. 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. VI. V VI Disconnect the riser from the BOP stack. Circulate the well after drill pipe disconnect. Circulate across the BOP stack to remove trapped gas. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

22 OISD RP 174 Page No 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) psi WP e) psi WP and f) 20,000 psi WP I IV. 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. Arrangement of choke and kill m a n i f o l d s h o u l d b e 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. The blind shear ram shell be capable of shearing drill pipe of any size and grade in the hole and seal the well bore under Maximum Anticipated Surface pressure. d. Ram preventers should be equipped with an integral or remotely operated locking system 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

23 OISD RP 174 Page No. 14 Sr.Number:OISD/DOC/2016/1 I IV. 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. VI. V 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. The remote panels should be connected to the control manifold in such a way that all functions can be operated independently from each panel. VI The Subsea BOP stack shall have two fully redundant control pods. Each control pod should contain all necessary valves and regulators to operate BOP stack and LMRP functions. The control pods may be retrievable or non-retrievable. To isolate the pods from one another, each control pod shall be connected to a shuttle valve that is connected to each operable function. IX. If one of the two PODS fails, the operations should be stopped, well secured and the faulty POD should be made operational prior to resume the further operations. IXA. Umbilical and Reels a. There should be two or more means of surface to subsea power fluid supply. The rigid conduit(s) are attached to the riser and provide the primary hydraulic supply to the subsea control pods. b. The hot line hose supplies power fluid from the surface to subsea control pods mounted on the LMRP. The hot line is run, retrieved and stored on the hose reel. c. The hot line(s) and MUX cable(s) should be secured to the riser by clamps to prevent corrosion and damage. The outer sheath of the hot line and MUX cable should be inspected visually for damage on retrieval. d. The hot lines should be tested at MWP of the system once a year. e. Re-terminations, repairs of Hot line and MUX cable should be tested at the RWP of the hose. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

24 OISD RP 174 Page No. 15 f. The MUX electrical cables supplies power and communication for control of the subsea pod functions. The MUX cable should be run, retrieved and stored on a cable reel. g. All underwater electrical umbilical cable terminations should be sealed to prevent water migration into the cable in the event of connector failure or leakage and also to prevent water migration from the cable into the subsea connector termination in the event of water intrusion into the cable. h. Individual connector terminations should be physically isolated so that sea water intrusion does not cause electrical short circuiting. i. The hose / MUX cable reel should be equipped with a brake, mechanical lock and guard. 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. Secondary control system: ROV (Remotely operated vehicle) intervention: a. The BOP stack should be equipped with ROV intervention equipment that at a minimum allows the operation of critical functions i.e. shear ram, one pipe ram, ram locks and unlatching of LMRP connector. b. The Hydraulic fluid can be supplied by the ROV, accumulators mounted on BOP stack or an external hydraulic power source maintained at the well site. c. All critical functions shall be fitted with single port docking receptacle designed in line with the requirements of API - 17H. If a multiple receptacle type is used, the receptacle and the functions should have positive identification. Acoustic control system: a) The acoustic control system is an optional control system designed to operate designated BOP stack and LMRP functions. It may be used when the primary control system fails to operate. b) The hydraulic accumulator system may be used for both the acoustic system as well as emergency control system. c) The acoustic accumulators shall be capable of being completely discharged subsea prior to recovering the BOP to surface. X Precharge pressure of accumulator bottle in case of 3000 psi WP unit should be /- 100 psi and in case 5000 psi WP unit should be 1500+/- 100 psi. Only Nitrogen should be used for precharge. XI 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

25 OISD RP 174 Page No. 16 XIV. If diverter control system is not self- contained, hydraulic power may be supplied from BOP control system. XV. XVI. 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. XV 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

26 OISD RP 174 Page No 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. I IV. 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 anticollapse 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. VI. V VI IX. 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. 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. X 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. 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 OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

27 OISD RP 174 Page No. 18 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. XVI. Wellhead and riser connector should be equipped with hydrate seal. 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. XV 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. XVIIA. An Emergency Disconnect Sequence (EDS) shall be available on all subsea stacks of Dynamically positioned drilling rigs. It is optional for moored drilling rigs. a. The EDS is a programmed sequence of events that operates the functions to leave the stack and control the desired state and disconnect the LMRP from the lower stack. b. The number of sequence, timing and functions of EDS are specific to the rig, equipment and location. c. There shall be a minimum of two separate locations from where the EDS can be activated. XVI 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. XX 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). XXI The Dynamically positioned offshore Deep water drillings should be provided with emergency BOP control system i.e. Autoshear and Deadman. a. The Autoshear is a safety system designed to automatically shut in the well bore in the event of an untended disconnect of LMRP. The Autoshear system should be armed while latching the BOP stack on to the wellhead. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

28 OISD RP 174 Page No. 19 b. The Deadman is a safety system designed to automatically shut in the wellbore in the event of a simultaneous failure of hydraulic supply and electrical supply of the drilling rig. The Deadman system should be armed while latching the BOP stack on to well head. c. The dedicated emergency accumulator system may be used for both the Autoshear and Deadman systems. 6.5 Choke and Kill Lines 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 from the wellbore completely, as required. I IV. 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 downs tream 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 downstream of chokes, provision should be made to isolate a failure or malfunctioning without interrupting flow. VI. V The choke manifold should be placed in a readily accessible location, preferably outside of the rig structure for Onshore rigs. All the choke manifold valves should be full opening and designed to operate in high pressure gas and drilling fluid service. VI 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

29 OISD RP 174 Page No. 20 X XI 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. XIV. The following are the recommendations for choke installation up to 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 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 for use in the event rig air becomes unavailable. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

30 OISD RP 174 Page No 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. I IV. 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. 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 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. I IV. 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 fail-safe-close valves adjacent to preventer. VI. V VI IX. 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: OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

31 OISD RP 174 Page No. 22 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. I IV. 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. 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. V VI 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. Kill lines should not be used for routine fill up operations. X All sharp bends in high pressure lines should be of targeted type. XI XIV. XV. XVI. XV 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. 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. Outlets of all sections of well head should have at least one gate valve. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

32 OISD RP 174 Page No Blowout Preventer Testing 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. I IV. BOP stack should be function tested for CLOSE and OPEN functions separately. The test should be preferably conducted when the drill string is inside casing except blind shear ram. Both pneumatic and electric pump of accumulator unit should be turned off after recording initial Accumulator pressure. V. All the blowout 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. VI. V VI IX. 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. Function test should be carried out alternately from main control unit / rig floor panel / auxiliary panel. Record the accumulator pressures dr op after each Close or Open function (with charging pump shut). The final accumulator pressures after all the functions should not be less than 200 psi above the recommended precharge pressure of accumulator bottles. X. All the gate valves and blow out preventers should be returned to their original position before resuming operations. XI. All the results should be recorded in the prescribed format (Annexure-VII) 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 choke, kill manifold / valves, kelly valves, Top-drive safety 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) I IV. Test BOP using cup tester or test plug (Preferably). 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

33 OISD RP 174 Page No. 24 V. High pressure testing unit with pressure chart recorder be used for pressure testing. VI. 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. c. Following repairs that require breaking a pressure connection. d. But not less than once every 21 days. VI IX. Low pressure test should be carried out at 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 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. X XI XIV. XV. 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, Top drive safety valve etc. would experience pressure during kick. FOSV, IBOP, Upper & Lower Kelly cock, Top drive safety Valves, HCR and Manual Valves, Choke & Kill line manifold shall also be pressure tested along with the BOP Stack at the same pressure. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

34 OISD RP 174 Page No Minimum Requirements for Equipment for Workover operations (on land) For workover operations: I. Stack arrangement for workover rigs should be same as per clause number 6.3 I IV. Kill line should be of minimum 2 inch size. 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 wells. (It is must for the wells having gas in the formation fluid and oil wells where formation pressure is hydrostatic or more) f o r 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. The minimum capacity of trip tank in work-over rigs should be 30 bbls. VI. V VI IX. 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. 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

35 OISD RP 174 Page No. 26 Sr.Number:OISD/DOC/2016/1 7.0 Procedures and Techniques for (Prevention and Control of Kick) 7.1 Cause of Kick Kick may be caused due to I. Encountering higher than anticipated pore pressure Reduction in hydrostatic pressure in the well bore 7.2 Cause of Reduction in Hydrostatic Head I Failure to keep the hole full of drilling fluid Swabbing I Loss of circulation IV. Insufficient drilling fluid density V. Gas cut drilling fluid VI. Loss of riser drilling fluid column 7.3 Kick Indications Primary Indications of kick: I. Increase in drilling fluid return rate Pit gain or loss Secondary Indication of kick: I. Changes in flow line temperature Drilling breaks I Pump pressure decease and pump stroke increase IV. Drilling fluid density reduction V. Oil & Gas show VI. Change in shape & size of drilled cuttings 7.4 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. I 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

36 OISD RP 174 Page No Precautions before Tripping Out I. Conditioning of drilling fluid prior to tripping out should be ensured. This should include: I IV. a. No indication of influx of formation fluids. b. The drilling fluid density in and out should not differ more than gm/cc (0.2 ppg.) in open hole. In cased hole there should not be any difference. A trip tank shall be lined up and function tested. Trip sheet shall be ready to be filled during tripping out to monitor the well behavior during pulling out operation (Annexure-VI). 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. 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 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 like yield point, gel strength should be taken. I Trip tank volume should be monitored and same should be recorded in the trip sheet (Annexure -VI). 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. The drill string should be on elevators during waiting. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

37 OISD RP 174 Page No. 28 Sr.Number:OISD/DOC/2016/ 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. I Circulation should be given to break gelation of mud as per requirements especially in deep wells and where heavy mud is used. With a float valve in the string, drill pipe should be filled up intermittently 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. Running in speed of casing/liner should be maintained considering allowable surge pressure 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. I IV. This should also include roles responsibilities of the personnel during kick. The following information should be pre-recorded for use in kill sheet preparation: casing data, s af e working pressure limit for surface BOP equipment, wellhead, casing string. maximum allowable casing pressure, contingency plan, pump rate (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). 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. V 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). VI 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

38 OISD RP 174 Page No Kick Control Procedures Following are recommended well control procedures for surface stack and sub-sea Surface Stack For onshore and bottom-supported offshore installations: A. During Drilling I. Stop drilling Pick up Kelly to position tool joint I 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). Soft shut in Hard shut in TABLE - 1 Sl. No. Soft Shut in Hard Shut in 1. Open hydraulic control valve Close Blow out Preventer. (HCR valve) / manual valve on choke line. (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, Allow pressure to stabilise and record SIDPP, SICP and Pit Gain. monitoring casing pressure. 4. Allow the pressure to stabilize and record SIDPP, SICP and Pit gain VI. V VI IX. Monitor the casing pressure. If the casing pressure is about to exceed MAASP, follow the contingency plan. Calculate the drilling fluid density required to kill the kick. Initiate the approved / selected well kill method. Check rig crew duties and stations. X. Review and update the well control worksheet. XI. Check pressures of all annuli of the well. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

39 OISD RP 174 Page No. 30 B. During Tripping During tripping whenever flow is observed: I. Position tool joint above rotary table and set pipe on slips. Install Full Opening Safety Valve (FOSV) in open position on the drill p i p e and close it. I 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. V VI IX. Initiate the approved / selected well kill method. Check rig crew duties and stations. Review and update the well control worksheet. Check pressures of all annuli of the well. C. When String is out of Hole I. Close blind / blind-shear ram. I IV. Record shut in pressure. Monitor the casing pressure. If the casing pressure is about to exceed maximum allowed (MAASP), follow the contingency plan. Calculate the drilling fluid density to kill the kick. V. Initiate the approved /selected well kill method. VI. V VI Check rig crew duties and stations. Review and update the well control worksheet. Check pressures on all annuli of the well. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

40 Sr.Number:OISD/DOC/2016/001 OISD RP 174 Page No Floating Installations (Sub Sea) A. During Drilling I. Stop drilling I IV. Position the tool joint for the BOP s operation. Shut down the drilling fluid pump(s). 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. V If the hard shut-in procedure has been selected: close Annular BOP and open the choke line with the choke in closed position. Observe the casing pressure, if it exceeds MAASP, follow the contingency plan. VI 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 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: 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. Close the hang-off rams. I 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. 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

41 OISD RP 174 Page No. 32 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 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. vii. viii. ix. Close the hang-off rams. 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. Connect the circulating head to the standpipe, open the safety valve. Allow the shut-in pressure to stabilize and record pressures. x. Determine the volume of the kick. xi. xii. xiii. xiv. xv. Calculate the drilling fluid density required to kill the kick. Select a kill method. Check rig crew duties and stations. Review and update well control worksheet. Inspect the BOP stack with television, if feasible B. During Tripping I. Install safety valve. I IV. Position the tool joint for the BOP s operation. Check the well for flow if it is flowing, follow shut in procedure. 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. V VI Observe the casing pressure, if it exceeds MAASP, follow the contingency plan. Check for trapped gas pressure. 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. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

42 OISD RP 174 Page No. 33 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 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. vi. Allow the shut-in pressure to stablise and record pressures. vii. Determine the volume of the kick. viii. Calculate the drilling fluid density required to kill the kick. ix. Select a kill method. x. Check rig crew duties and stations. xi. Review and update well control worksheet. xii. Inspect the BOP stack with television, if feasible OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

43 OISD RP 174 Page No. 34 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 C. When String is Out of Hole I. At the first indication of the well flowing, close the blind / blind-shear rams. I IV. Open the gate valve on the subsea BOP stack to open the choke line, close the choke line at the surface. Record shut-in pressures. Wt. (specific gravity) of fluid in the choke line should be considered for calculating shut-in casing pressure. Record the kick volume. V. Run the drill string in the hole to the top of the BOPs with NRV. VI. V VI IX. Add the hydrostatic pressure of the fluid in the choke line to the surface pressure to determine the pressure below the blind rams. 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 the riser with drilling fluid of the required density. Close the diverter. Open the BOPs and watch for flow. If the well does not flow, open the diverter and trip in the hole. 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. All the key operational personnel should have valid well control training certificate from IWCF/IADC accredited well control training centre. I While drilling in H 2S / 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. Organization 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. 1 Pit drill 2 Trip drill OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

44 OISD RP 174 Page No. 35 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 b. To conduct a 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. I IV. Stop drilling / other operation in progress. Position tool joint for BOPs ram closing. Stop mud pump V. Secure brake VI. V VI During / after the above steps, as applicable, designated crew should move to assigned positions Check for self-flow Record the response time. Trip Drill (Drill Pipe in BOP) I. Give signal by raising alarm. I IV. Position tool joint above rotary and set the pipe on slips Install full opening safety valve in open position. Close FOSV after installation V. Designated crew members should move to assigned position, during / after the above steps, as applicable. VI. V Close BOP Record response time. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

45 OISD RP 174 Page No. 36 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 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. I IV. Position upper drill collar box at rotary table and set it on slips. 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. Install FOSV in open position. V. Close FOSV. VI. V Close BOP. 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. I Close blind/ blind-shear ram. Record response time. Training Asstt. Shift Incharge / Asstt. Driller, supervisor and all the key operational personnel should have valid well control training certificate (of appropriate level) from IWCF/IADC accredited well control training center. 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. Flow rate sensor should be installed for monitoring return mud flow with high / low alarms. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

46 OISD RP 174 Page No. 37 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 I IV. Mud / pit volume totalizer 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 totalizer should have high / low alarm (visual or audible setting). 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. I 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. 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 Under Balanced Drilling Primary well control during Under Balanced Drilling (UBD) is maintained by flow and pressure control. The bottom hole 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 OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

47 OISD RP 174 Page No. 38 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 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). I IV. The return flow line shall have two valves, one of which shall be remotely operated and failsafe-close (ESDV). The flow line 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. 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 flow path. Applied surface backpressure should be kept to a minimum to reduce erosion of chokes and other surface equipment. 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 (H 2S) gas. VI. V VI The BOP stack, flow / diverter line, and bleed off and kill lines should be designed for exposure to H 2S in accordance with NACE (MR 075) / ISO specifications. Blind-shear rams should be considered for underbalanced drilling of wells with high Hydrogen Sulphide (H 2S) potential. A stab-in safety valve for the string in use should be available on the rig floor 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. I When running a work string under balanced, two NRVs shall be installed in the string as deep a n d as close together as possible. Installation of additional NRVs should be considered depending on the nature of the operation (i.e. high-pressure gas). The NRV should have a minimum working pressure rating equal to the maximum expected BHP. 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 down hole 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 snub in or kill the well prior to deployment. DIV should have working pressure rating of more than maximum expected differential pressure after closure. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

48 OISD RP 174 Page No. 39 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 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. V VI IX. At no time the well should be left open to the rig floor when the well is live. Trapped gas below the float should be removed safely before removing the float from the drill string during pulling out. If a well is killed prior to tripping, traditional tripping procedures including the completion of trip sheets should be followed. Round the clock supervision by competent persons should be ensured. All personnel involved in operations 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. X XI Appropriate PPE should be used by all personnel on the site. 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. 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. iii. iv. NRV failure, influx into work string during making connection or tripping in live well. Leaking connection below drilling BOP. Leaking rotating control device or flow line before ESDV, seal elements, connection to flow line, 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. vii. viii. Failure of surface equipment after RCD. This can be leaks or plugged equipment and lines. Work string failure. Emergency shut-in. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

49 OISD RP 174 Page No. 40 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/1 ix. Emergency well kill. x. Lost circulation. xi. H 2S 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 H 2S, no sour gas may be released to atmosphere at any time. XVI. Produced fluids containing H 2S or drilling fluids contaminated with H 2S should not be stored in open tanks. XV The flare stack shall be as per regulatory requirements. XVI If H 2S 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 tanks. XIX. A pressurized tank or a tank truck equipped with a functional H 2S scrubber should be used for the transportation of sour fluids off location. XX. Adequate provision should be made for the safe storage and / or disposal of produced fluids and drill cuttings. Reservoir liquids should not be stored in an earthen pit. Refer to MOEF guidelines for handling of drilling fluids and drill cuttings (OISD-RP-201) XXI. Explosive potential monitoring should be conducted at all the points where there is a potential of release of combustible vapours to atmosphere. XX For wells which contain H 2S, drill cuttings should be held in tanks equipped with vapour control. Vapour shall either be vented to a flare stack or through an H 2S scrubbing system. Another related technique of UBD is Managed Pressure Drilling (MPD). While UBD is mostly focused on maximizing the performance of the reservoir, MPD is more focused on successfully drilling the well, while minimizing the time and money spent on non-productive time (NPT), in addition to not damaging the formation in the process. While MPD utilizes some of the same surface equipment used in UBD; MPD, particularly in offshore environments, is not intended to produce hydrocarbons while drilling but rather to more precisely manage wellbore pressure and annulus returns while drilling through sections with very narrow margins between reservoir pore pressure and fracture pressure gradients. Any influx incidental to the operation is safely contained using an appropriate process. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.

50 OISD RP 174 Page No. 41 Sr.Number:OISD/DOC/2016/001 Sr.Number:OISD/DOC/2016/ Equipment Arrangement for HTHP Wells I. The installation should be equipped with: a. A fail-safe-open, remotely operated valve in the overboard line. b. A cement line pressure gauge in the choke panel, a remote camera in the shaker house, with display in the driller's house. c. A choke / kill line glycol injection system. d. High pressure and / or high temperature resistant seals should be installed in choke and kill lines, including flexible line hoses and the choke and kill manifold, packing in the kelly cock / internal BOP, packing / seal in the marine riser. I. Flexible kill-/choke line hoses should be inspected and pressure tested to maximum well design pressure prior to HPHT mode. Specification and qualification criteria for equipment and fluids to be used or installed in a HPHT well should be established, with particular emphasis on deterioration of elastomer seals and component as function of temperature/pressure, exposure time and well bore fluids. OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from the use of OISD Standards/Guidelines.