Oil Industry Safety Directorate

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1 No. 1 OISD-RP-238 FIRST EDITION April, 2016 For Restricted Circulation OISD-RP-238 April, 2016 Prepared by Functional Committee on Well Integrity Oil Industry Safety Directorate Government of India Ministry of Petroleum & Natural Gas 8th Floor, OIDB Bhavan, Plot No -2, Sector -73, NOIDA (UP) Website: Tele: , Fax:

2 Preamble No. 2 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 center for formulation of constantly updated world-scale 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 selfregulation 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

3 No. 3 FOREWORD The Oil Industry in India is more than 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 operation and maintenance practices at a national level was hardly in existence. This coupled with feedback from some serious accident that occurred in the recent past in India and abroad, emphasized the need for the industry to review the existing state of the 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 for 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 constituted a number of functional committees of experts nominated from the industry to draw up standards and guidelines on various subjects. The present OISD- RP-238 on Well integrity was taken up for formulating recommended practices and guide lines for maintaining well integrity of a well throughout its life cycle by a functional committee constituted for the purpose in the year This recommended practices covers guidelines to prevent unintended cross flow between the different pressured permeable zones and unintended flow of hydrocarbon from peaceable zones to the surface throughout the life cycle of a well from conception to production and abandonment. The document is based on the accumulated knowledge and experience and the various national and international codes and practices. The recommended practices are meant to be used as supplement and not as a replacement for existing codes and practices. The provisions of these recommended practices, if implemented objectively, may go a long way to improve the safety and reduce incidents related to well integrity on onshore and offshore wells Users are cautioned that no guidelines can be a substitute for the judgment of responsible and experienced personnel involved in exploration and production operations. These recommended practices in no way, supersedes the statutory requirements of bodies like DGMS, PESO or any other Government Body which must be followed as applicable. Suggestions are invited from the users after it is put into practice to improve the document further. Suggestions for amendments to this document should be addressed The Coordinator Functional Committee on Well Integrity, Oil Industry Safety Directorate Government of India Ministry of Petroleum & Natural Gas 8th Floor, OIDB Bhavan, Plot No. 2, Sector 73, Noida (U.P.) Website: Tele: , Fax:

4 No. 4 NOTE Oil Industry Safety Directorate (OISD) publications are prepared for use in the Oil and Gas Industry under the Ministry of Petroleum and Natural Gas. These are the property of Ministry of Petroleum and Natural Gas and shall not be reproduced or copied or loaned or exhibited to others without written consent from OISD. Though every effort has been made to assure the accuracy and reliability of the data contained in these documents, OISD hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use. These documents are intended only to supplement rather than replace the prevailing statutory requirements.

5 No. 5 FUNCTIONAL COMMITTEE ON "WELL INTEGRITY NAME ORGANISATION Shri TARSEM SINGH OISD 2. Shri V K GUPTA ONGC, IDT DEHRADUN 3. Shri R K SINGH RIL MUMBAI 4. Shri SANDEEP NAYAK BGEPIL MUMBAI 5. Shri HARISH TANEJA CAIRN INDIA LTD 6. Shri A K JAIN OISD CO-ORDINATOR

6 C O N TE N TS SECTION DESCRIPTION PAGE NO. 1.0 INTRODUCTION PURPOSE AND SCOPE DEFINATIONS BARRIER TERMINOLOGY SUFFICIENT AND ACCEPTABLE WELL BARRIERS WELL BARRIERS WELL INTEGRITY MANAGMENT WELL BARRIER IMPAIRMENT TESTING OF BARRIERS REFERENCES 21

7 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No Introduction: Wells are physical assets which connect the subsurface hydrocarbon bearing reservoirs to the surface and through which oil, gas, water, other contaminants are produced. The wells are designed and placed such that it provides sufficient barriers to effectively contain and control the flow of formation fluids from the formation / reservoir which the well penetrate. Each well has finite life, commences from drilling operations. Thereafter, the well is exposed to various other operations like completion, production, stimulation, intervention, work over, abandonment etc. during its life cycle. The well integrity may be described as The instantaneous state of the well, irrespective of purpose, value or age, which ensures the veracity and reliability of the barriers necessary to safely contain and control the flow of all fluids within or connected to the well thus authenticating the well as either safe to operate or intervene or suspend or abandon. Well Integrity management is the application of Technical, Procedural or Organizational controls to minimize the risk of uncontrolled release of formation fluids as well as preserve the formation from the adverse effects of outside influences that can affects its ability to produce throughout the life cycle of the well. In other words, well integrity refers to reducing the risk of cross flow between zones of different pore pressures, uncontrolled and unintentional flow from the zones to the surface and environment, uncontrolled and unintentional flow (both in magnitude & direction) of fluids out of or into the formation and other zones throughout the life cycle of the well. 2. Purpose and Scope: The Well Integrity recommended practices are developed by the OISD to ensure adequate safety and operability during life cycle of oil and gas wells in the E&P industry in India. The Scope does not cover CBM wells. The minimum requirements noted in this document are applicable to all components between the reservoir producing interval and the outboard flange X-mas tree wing valve

8 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No Definitions: 3.1 Barriers The barriers are the design envelopes, which comprise the system or systems, which may be a combination of physical well barrier elements (so called safety critical elements SCE), designed to contain and control well fluids and well pressure from one formation to another and to the surface. Typical physical well barrier elements include: a. Casing and cement b. Wellhead and X-mas tree c. Well intervention pressure control equipment d. Well control equipment such as BOPs /FOSV/IBOP e. Imposed hydrostatic column ( If it can be monitored) f. Valves g. Cement / Mechanical plug 3.2 Shut-in / Temporary suspended well For offshore wells, Shut-in or temporary suspended well is a flowing well completion with X- mas tree, master valves, wing valves and Down Hole Safety Valve (DHSV) or Sub Surface Safety Valve (SSSV) closed. The pressured hydrocarbon fluid will be present at least below the production packer in the production casing and below the closed DHSV / SSSV in the tubing. There may be fluid above the DHSV / SSSV depending on the sequence of valves closed. For onshore wells, Shut-in wells or suspended well is a Flowing well completion with X-mas tree, master valves and wing valves. The pressured hydrocarbon fluid will be present below the closed master valve in the tubing and at least below the production packer in the production casing (below the well head seals in the production casing in case of packer less completion).

9 OISD RP 238 No Barrier Terminology: 4.1. A barrier may be closed and not easily opened (e.g. bridge plug or cement), closed and easily opened (e.g. wire line plug or valve) or normally open but ready to close (e.g. x-mas tree or BOP) A fluid may be considered to constitute a barrier provided that the level of the fluid can be monitored and maintained Barrier Classification: 1. Primary Barrier: A system which provides the first line containment ii. Secondary Barrier: A system which provides backup containment to the well fluids and pressure in case of failure of the primary barrier 5 Sufficient and Acceptable Well Barriers: 5.1 At all times where there is the potential for differential pressures that can induce flow, there shall be two independently tested barriers in each flow path between hydrocarbon bearing or potential hydrocarbon bearing or abnormal pressured water permeable zones and surface. 5.2 During normal operating conditions (production operations), one of these two barriers in each flow path shall be below seabed/ground level. For onshore wells, the operator should carry out detailed risk analysis for placement of down hole barriers) The types of barrier should be appropriate to the flow path, the future utilization and the expected life of the well The integrity of the SCE of each barrier should have been pressure and/or inflow tested when installed, if applicable. Barriers, which are open and ready to close or closed and easily opened should be subsequently tested at regular intervals. Integrity of the barriers which cannot be opened or closed after installation should be monitored regularly, wherever feasible. (Like casings, cement, production packers by monitoring annulus pressure behavior). 5.5 If any one of these barriers does not meet these criteria, a risk-based decision should be taken using an appropriate process to determine whether the risk is manageable. The results of the risk assessment will form a mandatory element of the internal dispensation process.

10 OISD RP 238 No Well Barriers Operation Leak path Barriers / Barrier elements Drilling Drill string bore Primary- Drilling fluid column, Secondary Top drive valve or Kelly cock, FOSV (during tripping), Float sub, BOP shear / blind ram. Drilling Drill string open hole / casing annulus Primary Secondary BOP stack Drilling fluid column Drilling and Completion Logging Production logging Casing / open hole bore Well intervention Primary - Drilling / completion fluid column, Secondary - BOP with blind cum shear ram, Wire line BOP with lubricator Primary Lubricator and stuffing box Secondary- Wire line BOP with shearing capability and X-mas valves Well testing Inside of Well Test String Primary - Tester valve, SSTT (subsea), Flow head, Well Test Choke Manifold. Secondary - BOP BSR Well testing Test string well annulus Primary - Test Packer/tubing envelope. Secondary - Casing, Well Test Fluid in Test String annulus, BOP Stack, Wellhead Side outlet valves.

11 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No. 5 Production Inside tubing string Primary DHSV / SSSV. Secondary - X-mas tree valves, crown valves Production Annulus Primary - Production packer. Secondary - Casing, cement rise behind casings Well head seals, Annuals valves, Change over from Inside tubing Primary DHSV / SSSV / plug / BOP to X- mas tree Formation isolation valves Secondary - Back pressure valve / plug. Drilling ( Well without drill string ) Casing lowering Casing / open hole bore Primary Drilling fluid Inside of the casing string being lowered column Secondary BSR BOP Primary Drilling fluid column, Tested Float collar valve up to formation pressure. Secondary Casing shear ram, if available or Annular BOP., FOSV made up with crossover and ready to use Casing lowering Annulus casing being lowered previous casing / open hole Primary - Drilling fluid column Secondary Annular BOP / casing ram (if available) BOP 7. Well Integrity Management 7.1 Reservoir Characteristic The first step of Well Integrity management is to have clear understanding of the reservoir and fluid characteristics. For this the following information are to be collected and analyzed. - Geological data of the area and nature of the reservoir ( This involves depositional environment, reservoir geometry, rock composition, fluid saturation, depth, thickness, pore pressure gradient, fracture gradient, temperature gradient, faults and barriers, sedimentary / lithological sequence, geographical location, mechanical properties like hardness, porosity, permeability etc. ).

12 OISD RP 238 No. 6 - Lithostratigraphy, fluid content, pore pressure and the overburden gradient. - Nature of reservoir fluid including gravity of oil, gas and water, its ease of transmissibility within the reservoir, connectivity i.e. porosity and permeability, the maximum expected pressure at surface upon gas percolation and the impurities especially CO2 and H2S expected in the formation fluid of the reservoir and other formations traversed. - Production condition of the reservoir like depletion, pressure support, and enhanced recovery practices in practice, condition of production facilities. - Anticipated production problems having impact on well integrity such as formation of wax, scales, hydrates etc. - MAAOP (maximum allowable annulus operating pressure) for all intermediate casings in case the casing shoe is exposed to formation - Well drilling / completion data - Past log data & seismic survey data - Production and injection data The above mentioned information and data should be made available from well histories of past drilled off set wells, recorded logs, seismic logs of the area, production testing records of the wells in the area prior to planning the well activities. 7.2 Well construction. Robust well construction is the most critical step in well integrity management as it defines the first set of criteria on which all the subsequent barriers to flow will be designed. The following are the important points to be taken care off while planning well construction for well integrity.

13 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No Surface casing should be set to seal off upper unconsolidated weak formations, upper fresh water bearing formations. The surface casing should be designed to with stand the upset loading of the entire well head & casings, to be lowered in the well. The Surface casing design should be adequate for the worst conditions of burst, collapse and tensile loading anticipated during drilling operations and subsequent life cycle of the well. The wall thickness and yield strength of the surface casing should be adequate to withstand the bending loads which may be applied to the surface casing throughout the life of the well. The surface casing should have adequate foundation strength Surface casing should have adequate structural strength and fatigue life to with stand cyclic weather and current induced loads The setting depth of the surface casing should be such that it isolates any shallow gravel beds, upper loose sands, un consolidated rocks. It should allow fluid return back to sea bed or surface without any seepage, while the next section is being drilled If, there is a possibility of shallow gas or oil /gas, the setting depth of the surface casing should be selected to minimize the risk of uncontrolled flow caused by fracture of the upper weak sedimentary formations. The surface casing should be set prior to open the hydrocarbon bearing zone As the surface casing has to with stand the loads of entire well head along with next casings, the top of cement behind the surface casing should be up to the surface. In case of offshore wells, it should be either at sea bed or closer to the mud line in subsea to protect against bending induced failure The connectors / couplings of surface casing should be selected ensuring that they will not unlatch inadvertently Efforts should be made to ensure that the drilled hole is cleaned of drilled cuttings and stabilized prior to lowering casing to avoid the chances of short landing of casing

14 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No Casings For the purposes of this document casings include conductor, surface casing, intermediate casing(s) and production casing Casings combined with good cement bond provide a strong and long lasting barrier to flow of formation fluid through annulus Well must incorporate sufficient intermediate casings, so designed and constructed to prevent uncontrolled flow of formation fluid at surface, subsea or underground and to prevent undesired release of formation fluid Casing should be inspected and tested as per API RP 5CT The casing plan should be configured to accommodate all Identified sub surface hazards and to minimize risk either from cross flow between formation of different pore pressures or the uncontrolled release of formation fluids to surface throughout the life of the well. The casing setting depths should be selected to provide an adequate safety margin between the formation strength and anticipated pressures during well control operations. It should also be selected to provide sufficient margin between formation strength and anticipated pressures during casing cementation pumping operations Casing should be designed to with stand the worst anticipated conditions of burst, collapse, tensile and tri axial loading during keeping in view intended purpose of the well Casing should have adequate properties to contain the maximum load which it may be exposed during life cycle of the well. There should be sufficient margin for deterioration in service due to wear, erosion, corrosion during life cycle Production casing should be able to accommodate a leak in the production tubing at the well head level and with stand the shut-in well head pressure plus packer fluid head Well integrity envelopes should be set up with adequate design safety factors for Burst, Collapse and Tension. Design factors will be based on the risk analysis and load cases envisaged The material specification of production casing should be suitable for the properties of the anticipated formation fluid (including special considerations for fluids containing H2S gas) to which it may be exposed.

15 OISD RP 238 No For wells having gas lift or H2S in well fluid, production casing should have gas tight premium thread connections to ensure reduction in risk of gas leakage to outer annulus. All the casings to be pressure tested prior to drill float collar / as well as float shoe. The test pressure should not exceed 70% of the burst pressure of the weakest pipe in casing string or RWP (Rated Working Pressure) of Well head, whichever is less. In deciding limit of test pressure, due consideration is to be given to the following. a. Burst rating of the weakest casing in the casing string. b. Density of fluid column inside and outside the casing. c. Effect of the test pressure on tensile load of the casing considering the design safety factor. d. MAASP should be calculated and always available Liner hanger should be tested at pressure 70% of the burst rating of previous casing (on which it is set ) or RWP of Well head, whichever is less. Due consideration is to be given to density of fluid inside and outside the casing and effect of test pressure on the tensile loading of casing string The integrity of a Liner tie back should be tested considering worst case of maximum well shut in pressure against gas, with a surface leak in the production tubing and with packer fluid in the annulus Detailed casing records should be kept for well integrity management. Following should be indicated in the records: a. Casing lowering depth. b. Shoe & float collar depth. c. Size, grade, nominal weight and connection type, make up torque. d. Centralizers number and positions. e. Formation tops particularly porous zones and hydrocarbon zones. e. Cement rise behind casing. g. Test pressure and fluid density inside and outside casing at the time of testing.

16 OISD RP 238 No Drilling Fluid Drilling fluid is a key primary barrier to flow of formation fluid during balanced drilling operation The density of drilling fluid should be designed such that ECD (Equivalent Circulating Density) i.e. Original density of drilling fluid + Dynamic annular pressure losses should not exceed the formation strength of the weakest formation during drilling operation and well control operations The type and composition of drilling fluid should be compatible to the formation and reservoir fluid Mud weight should be maintained between the kick tolerance or Kick margin consider using psi/ft for the desired overbalance, since these are measured in psi/ft or psi. In other words, the mud or drilling fluid should be sufficient enough to control the pore pressure and ensures that formation fluid do not enter the well bore. For sections having insufficient drilling margin, quantitative risk analysis should be carried out considering swab during pulling out, surge during running in, ECD / EMW during drilling and LOT. On the basis of risk assessment, continuance of drilling or revision in well construction should be decided Circulation should be limited to a single active tank for effective loss / gain monitoring and pit management.

17 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No Cementation The purpose of the cementation is to isolate the well and to prevent the cross flow of the formation fluid, protect the casing from corrosion, isolate non targets, and to prevent leakage Surface casing should be cemented back to mud line / surface All hydrocarbon zones should be isolated from surface Intermediate and production casing should normally be cemented back to previous casing except the following a. Where, later side track is expected like multi-lateral wells. b. In a subsea well, where the casing annulus cannot be bled off. c. To prevent losses in weak formations. d. Cuttings injection down a well annulus It should be ensured that cement rise is minimum 150 feet in deep waters and minimum 300 feet in others above the top of the upper most hydrocarbons bearing zone Prior to cementation, it should be ensured that proposed cement slurry should be compatible to the exposed formations. It means that the exposed formations should be capable to with stand the hydrostatic head of the cement column. Primary well control must be maintained during pumping cement slurry and cement curing / setting time. Pumping rate of cement slurry should be selected to maintain required ECD for primary well control and to prevent seepage losses in the open hole. The cement slurry should also be compatible with anticipated down hole temperature conditions The cement should be given sufficient curing time based upon lab testing results for thickening time / surface sample prior to resuming further operations. Ensure that cement has acquired adequate compressive strength before beginning well head installation job Cement evaluation should be carried out for verification of cement bonding behind intermediate casings having hydrocarbon bearing zones behind it and production casing If casing is intended not to be run up to the bottom of drilled hole, the rat hole should be filled with high density and high viscous pill. This is to prevent falling of cement into the rat hole and displacing the rat hole fluid resulting in poor cement bond against shoe. In other words, rat hole mud density should be kept more than cement slurry average density to prevent cement slurry contamination with mud resulting in poor cement bondage with casing.

18 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No With casing at bottom, circulation is to be given prior to cementation at least for one cycle to clean the hole from cuttings, wherever feasible. ( ECD should not exceed the strength of weakest exposed formation 7.6 Wellheads Well head and its seals are one of the main key barriers at surface to flow of formation fluid through annulus. For design, selection and testing of the barrier following are the guidelines. Surface well heads The rated working pressure of the Well head should be more than the anticipated maximum shut in wellhead pressure, during drilling and production phases Wellhead and all its components like seals, rings, outlet valves etc. should have a temperature rating compatible with the minimum and maximum anticipated well head temperature during the life cycle of the well Materials of the well heads should be compatible with the chemical composition of the formation fluids, injection fluids, power fluids Well head joints and its seals should be tested with oil as testing fluid after installation at pressure least of the following keeping side outlet valves open % of Collapse rating of the inner casing. 2. Anticipated surface pressure, the well will see during its life cycle % of the well head lower flange rating First section of Well head (Weld on type) should be tested at 80 % of collapse pressure rating of the surface casing on which it is welded Surface wellheads must have side out access to all annulus to allow pressure to be monitored and bled off or pump fluid from the annulus. During drilling and well intervention, the side out let must be fitted with two full opening safety gate valve Side outlet configuration and valve set on non-active (not in communication with the section being drilled) surface wellheads and drilling spools shall be: a. For starter heads, one full-bore valve, a needle valve and a pressure gauge shall be fitted on one side outlet. The full- bore valve shall be open to allow annulus monitoring. The other side-outlet shall have a VR plug and ported blind flange installed. Wherever VR plug installation is not possible, it shall have a gate valve and ported blind flange installed with needle valve and pressure gauge.

19 OISD RP 238 No. 13 b. For subsequent spools, two full-bore valves shall be fitted to one side-outlet complete with needle valve and pressure gauge. The valve shall be open to allow annulus monitoring. The other side-outlet shall have one full bore valve, a VR plug and ported blind flange installed. Wherever VR plug installation is not possible, it shall have a gate valve and ported blind flange installed with needle valve and pressure gauge (in cases of artificial lift wells / inability to use VR plug) Gauges must be fitted to monitor annular pressures and should be accurate The first valve adjacent to well head body is to be kept as Stand by Up to date records of well heads should be kept showing the following 1. Date and time of testing 2. Test pressure and holding time 3. Side out let valve configuration. 4. Testing fluid Subsea well heads shall meet the requirements of API 17D. 7.7 Drilling operation practices The drilling practices mentioned below will help in well integrity management, a. Before drilling each section of the well, it should be ensured that Rotary table is centered with respect to well and Mast is centered with respect to rotary table to minimize wear and tear of Casing and well head. b. Frequent directional survey should be recorded by Gyro or Multi- shot or drift recorder or MWD so that exact location of prospective layer is known in TVD. c. In a directional well, use of mud motor should be preferred to reduce wear and tear of casing at deviated portion of the well due to high rotary rpm. d. Casing wear is a potential risk if higher than anticipated rotating time occurs. Extended fishing time, an unanticipated sidetrack or slower than anticipated drilling rate could lead to casing wear problem. The following are best practices: Monitor increase in amounts of fine steel shaving seen in cutting samples. Consider using ditch magnets to monitor amount of steel recovered daily to analyze wear anomalies. Optimize drilling time to minimize pipe rotation as much as practicable, in particular when nearing total depth. Higher hang-down weights impart increased tension in drill string and result in larger wear forces on shallow casing string. Use motors where practical and limits back reaming if rotation time is excessive or if steel shavings are seen in cutting samples.

20 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No. 14 If extended rotating time or protracted fishing operations occur while drilling the well, such conditions may dictate running a casing inspection log to caliper wall thickness. If any significant wear or damage is identified, running a protection string of casing should be considered to maintain wellbore integrity. e. Leak off test or Formation Integrity Test should be carried out after each casing lowering and cementation to assess the maximum allowable limit of shut in pressures and drilling fluid density. f. Use of centralizers should be considered to keep the casing in the well center to ensure that casing is cemented uniformly along it s circumference, especially in deviated wells. g. Prior to lowering large diameter casings ( 13 3/8 or larger ), It should be ensured that the drilled hole is proved and clean and drilling fluid is having sufficient lubricity so that the possibility of short landing of casing is minimized. In the deviated holes, drilled cuttings accumulate at the low side of the hole and form cutting beds. These cutting beds also create conditions for short landing of casing. These cuttings should be removed with high rotations of drill string, high drilling fluid discharge and sweeps of weighted high and low viscous pills. h. In deviated wells, rate of change of angles should be maintained uniform and constant to avoid high dogleg severity. The high dog leg severity can cause short landing of casing and poor cement bonding. i. Casing shoe and Float collar should not be placed against the hydrocarbon bearing formation. j. Negative test should be carried for production casing, after designed WOC by displacing entire volume of drilling fluid with clean water following procedure of staged displacement and holding for 30 minutes. k. Positive test should be carried out by applying pressure equal to 70% of production casing burst rating with clean water inside the well and holding for 30 minutes. (During positive test, all annular valves should be in open position. l. Accurate flow, meters, pressure gauges should be installed and maintained for accurate monitoring. m. MGS (Mud gas separator) to be used to circulate out a kick in a controlled manner. (MGS are not designed to handle a large volume of uncontrolled flow like, when diverting shallow gas flows or gas influx in the subsea risers). n. If a well is to be sidetracked due to stuck string after well killing operations, it is recommended to cement up or plug BHA before conducting a back off fishing operation. Leaving an un plugged BHA may act as a conduit for gas to kick through. o. BOP drills, Trip drills, Pit drills are to be carried out regularly to enhance the early kick detection capability and response time. The drill details are to be documented and analyzed. p. BOP pressure tests function test and scheduled inspection & certifications are to be carried out as per API Standard 53.

21 OISD RP 238 No Logging Operations Wire line double ram BOP should be installed and pressure tested at anticipated surface pressure prior to logging operations in operating wells Drilling fluid level in the well should be monitored continuously during logging operations on drilling units Logging tool pulling out speed should be controlled to avoid swabbing. 7.9 Production Annular Pressures during production phase The annular space between completion string and casings are either monitored or hidden and may or may not contain fluid based on the well design and construction. Where possible, the pressures of all annuli shall be monitored and where pressures are recorded, the type of pressure and source shall be determined. Operating companies should have established system and procedures for annulus pressure management. Types of annular pressures are: a. Thermally Induced Annular pressure (TIAP): This is pressure that arises due to the expansion of a finite amount of fluid in a finite annular volume based on temperature variations of the produced fluid. It is usually bled off at the inception of production and thereafter can be maintained below MAWOP. b. Trapped Annular Pressure: Where the casing design makes it impossible to bleed of the TAP, usually in subsea wells, this pressure is termed a trapped annular pressure (TAP) and is normally taken into consideration in the well design and load case envelopes. The design shall ensure that the TAP never goes above MAWOP. c. Sustained Casing Pressure: Where a pressure in an annulus is higher than MAWOP, and returns to or close to its original value after being bled off, this is termed sustained casing pressure (SCP). SCP is undesirable in any well and shall be addressed by a workover, repair or risk based dispensation to bring the well back into a safe operating envelope.

22 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No The sources of annular pressure during production are: External applied pressure Thermal induced pressures due to thermal expansion of fluid or dissolved gas evolution from annulus fluid. Ballooning of adjacent annuli. Sustained annulus pressure due to barrier failure, poor casing design, poor cementation, leak in completion string, loss of packer / seal integrity, loss of formation integrity, leak in control line, hanger seal failure, shallow pressure source, leakage in subsea crossover valves etc Sustained casing pressure is any measurable annular pressure at the casing head that rebuild to essentially the original annular pressure after being bled down or not possible to bleed down and is attributable to causes other than an artificially applied pressure which remain isolated from other annulus or temperature fluctuations in the well Sustained casing pressure is an indication of leakage in the well barrier system and it may lead to potential for loss of well control at the surface or sub surface The maximum Allowable Wellhead Operating pressure (MAWOP i.e. measure of the maximum pressure that can be safely applied to an annulus) should be assessed for each annulus. The MAWOP for the annulus being evaluated should be the lesser of the following. 50% of the minimum yield pressure of the casing or production riser string being evaluated. 80% of the minimum yield pressure of the next outer casing. 75% of the minimum collapse pressure of the inner tubular pipe body. For the outermost pressure containing casing MAWOP should not exceed 30% of its maximum internal yield pressure. The strength of the formation (FIT/LOT) should also be considered as one of the envelopes. The factor of safety considered for assumption of percentage of under rating are erosion and corrosion of the pipe, casing wear and tear during drilling next phase and age effect The trending of annulus pressures shall be monitored and documented. Fluid type added or removed to be recorded Operational changes related to the well / other adjacent wells, surroundings should be monitored and documented.

23 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No Wells having annulus pressure above MAWOP but below MAASP should be bled to zero and a close watch should be kept to monitor the behavior of annuli pressures. Depending on the analysis of pressure trending, action to reduce the pressure like lubricating and bleeding (Lube and Bleed, volumetric method) should be planned and executed. If pressure builds back above MAWOP, but stay below MAASP, a risk analysis and dispensation as per internal dispensation process to continue to operate the well may be sought. Liquid filled annuli pressure rises up quickly and bleeds off quickly. Gas filled annuli pressure rises up slower (depending on total gas volume) and bleed down slower. Repeated bleed-offs may enlarge the leak under some conditions For wells having annulus pressures > MAASP which cannot be managed to stay below MAWOP by lube and bleed, a risk analysis should be carried out and if considered safe to do so, a pressure relieve system may be used to manage this pressure. If not, production should be suspended & work-over like cement squeezing, replacement of defective production casings, casing patch, replacement of defective packer, side track the well etc. should be carried out to rectify the cause of annulus pressure For annulus pressure due to injection of gas / water, rate of injection, method and interval of injection should be reviewed. The injection rate, method and interval of injection should be selected such that the annulus pressure must not exceed MAWOP of production and / or outer annulus Well should be plugged and abandoned if mechanical integrity of the well is lost, reservoir is depleted or there is no future utility Work over operations for surface / platform wells If the outer annulus and production casing annulus have pressures in it above the acceptable limit, the reason for the same should be diagnosed and detailed workover program should be prepared accordingly During subduing the well by bulldozing technique, the outer and production annulus should be monitored critically. It should be ensured that the annulus pressure do not exceed MAWOP for that annulus The bottom part of the well should be abandoned by permanent abandonment procedures for side tracking operation After stabilizing the well, observe the well for the time period equivalent to the anticipated time required to remove X-mas tree and installation of BOP plus safety margin. If well remains stable, one complete cycle of circulation is to be given prior to removing X-mas tree for BOP installation. High viscous pill may also be placed to minimize gas migration in gas wells.

24 OISD RP 238 No Before disconnecting x-mas tree, two independent barriers should be ensured Work over BOP Stack should have one variable ram and one shear cum blind ram BOP should be tested at maximum anticipated surface pressure prior to resuming operations. For old wells, where test plug compatible to wellhead not available, high pressure test should be done with a cup tester limited to 70% of burst rating of exposed casing above cup tester After release of production packer, completion string should be pulled out in controlled manner to avoid swabbing For zone isolation, cement plug / bridge plug should be placed as near to the perforated interval as possible Well Abandonment Permanently plugged wells shall be abandoned with an eternal perspective, i.e. for the purpose of evaluating the effect on the well barriers installed after any foreseeable chemical and geological process has taken place Abandonment /suspension procedures shall address prevention of potential leakage of formation fluids to surface in accordance with Barriers to flow, permanent isolation of open hole or perforations from surface in accordance with barriers to flow, isolation of different permeable and / or hydrocarbon bearing zones, long term integrity of the abandonment /suspension For temporary abandonment of wells having open hole, bottom most cement plug should be placed as close to the source of inflow as possible. It should seal or isolate all possible leak paths The isolation plug should be placed at a depth having formation strength more than formation pressure There should be a provision of at least two barriers for temporary abandonment of well. One barrier should be preferably a mechanical barrier and second a cement plug. (Float valve not to be considered as a mechanical barrier as it is designed to prevent back flow of cement slurry from annulus due to differential pressure and not to counter formation pore pressure.) The cement plug (second barrier) should be placed at previous casing shoe. (Cement plug length 60 meters, 30 mts below shoe and 30 mts above shoe) Cased hole perforations should be isolated by Balance plug method, squeeze method or Cast iron bridge plug setting above perforation. It should be preferred to isolate perforations by placing a cement plug on the top of Cast iron bridge plug

25 OISD RP 238 No Plug location and strength should be tested by putting weight on it with drill string after designed setting time. In rig less abandonment, the location of the cement plug should be verified with the help of wire line and / or from the following: Volume of cement slurry pumped Displacement volume Return fluid volume Pump volumetric efficiency Steel volume The strength / integrity of the cement plug should be verified with application of pressure 1000 psi for bottom and back up plugs and 500 psi for top plug In subsea wells, a negative test is to be carried out before disconnecting BOP stack / riser from the well head during permanent or temporary abandonment Temporary Shut-in wells should have a Pump through type tubing plug or Injection valve capable of preventing back flow. Well should be Shut-in by closing the Master valve of the Valve tree and Wing valve of the annulus. Provision shall be made for recording Tubing as well as annulus shut-in pressures at least six monthly Offshore Wells shut-in for longer periods should be abandoned temporarily or permanently, as the case may be, at the earliest to minimize the risk of loss to property and environment and marine life due to possible hydrocarbon leakage. HIRA (Hazard Identification & Risk analysis) should be carried out for assessment of risk and taking additional safety measures. The shut-in wells should be equipped with a pump through type tubing plug and a surface controlled SSSV / DHSV. It may also be equipped with an injection valve capable of preventing back flow. Periodic monitoring of safety parameters / checking subsea tree valves DHSV/SSSV etc of the shut-in wells should be carried out, documented and analyzed. A contingency plan, for the envisaged emergencies including procedures, required resources (including location, transportation) should be developed and made readily available for the shut-in wells 8.0 Well Barrier Impairment Situations where the function of the well barrier is weakened, but are still acceptable should be defined. Operation should thereafter proceed, subject to a dispensation only after a risked based assessment is made using a appropriate process to determine if the risk is manageable.

26 OISD RP 238 No Testing of barriers. Barrier Procedure Acceptance criteria Drilling fluid Measure Specific gravity and viscosity. Check for self-flow. Drilling fluid specific gravity should be > formation pressure MWE Zero self-flow rate. Casing After cementation & WOC, pressure test casing to required pressure. Hold pressure for 15 minutes. Pressure shall not decline more than 10%. Zero leakage Well control equipment As per OISD-RP-174 or API- Standard-53 As per OISD-RP-174 Wire line Maximum anticipated surface Zero leakage BOP. pressure + 10% SCSSV / DHSV Refer API -14B (ANNEX E, E- 2) Acceptable Leakage rate Liquid < 200 CC / minute. Gas < 5 cc / Production Positive test to the 110% of Zero Leakage packer maximum operating pressure Wellhead As per OEM guidelines Zero leakage seals Liner As per OEM guidelines The pressure should not decline hanger more than 10% in 30 minutes seals duration. Further it should not decline more than 10%. The pressure applied should be equal to maximum anticipated pressure on the liner hanger psi. X-mas tree As per OEM guidelines Zero leakage valves Tubing Pressure test against a plug in a nipple The pressure should not decline to the WH pressure rating. more than 10% in 30 minute duration. It should not decline more than 10%.

27 OISD RP 238 Sr.Number:OISD/DOC/2016/1 No. 21 References 1. OISD RP API Standard CFR (Code of Federal Regulations0, API RP API RP API BUL E3 7. NORSOK D UK regulations 9. Mocando incident investigation report 10. Well control by Neal Adams 11. Casing design by Jim Short

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