Api rp 16st 2009 (2014) (american petroleum institute)

Coiled Tubing Well Control Equipment Systems API RECOMMENDED PRACTICE 16ST FIRST EDITION, MARCH 2009 REAFFIRMED, DECEMBER 2014 Coiled Tubing Well Control Equipment Systems API RECOMMENDED PRACTICE 16ST FIRST EDITION, MARCH 2009 REAFFIRMED, DECEMBER 2014 Special Notes API publications necessarily address problems of a general nature With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees make any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assume any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication Neither API nor any of API's employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights Users of this recommended practice should not rely exclusively on the information contained in this document Sound business, scientific, engineering, and safety judgement should be used in employing the information herein API publications may be used by anyone desiring to so Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict API publications are published to facilitate the broad availability of proven, sound engineering and operating practices These publications are not intended to obviate the need for applying sound engineering judgment regarding when and where these publications should be utilized The formulation and publication of API publications is not intended in any way to inhibit anyone from using any other practices Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard API does not represent, warrant, or guarantee that such products in fact conform to the applicable API standard All rights reserved No part of this work may be reproduced, translated, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher Contact the Publisher, API Publishing Services, 1220 L Street, N.W., Washington, D.C 20005 Copyright © 2009 American Petroleum Institute Foreword Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent Shall: As used in a standard, “shall” denotes a minimum requirement in order to conform to the specification Should: As used in a standard, “should” denotes a recommendation or that which is advised but not required in order to conform to the specification This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C 20005 Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years A one-time extension of up to two years may be added to this review cycle Status of the publication can be ascertained from the API Standards Department, telephone (202) 682-8000 A catalog of API publications and materials is published annually by API, 1220 L Street, N.W., Washington, D.C 20005 Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW, Washington, D.C 20005, standards@api.org iii Contents Page 1.1 1.2 Scope General Operations Not Covered in this Document Normative References Terms and Definitions 4.1 4.2 4.3 4.4 4.5 Well Control Equipment General Coiled Tubing (CT) Operations Well Control Components Additional Well Control Components Well Control Equipment for Hydrogen Sulfide Service 10 10 10 26 31 32 5.1 5.2 5.3 5.4 5.5 CT String and Connectors CT String CT String Selection CT Collapse Bend Cycle Fatigue CT String Management 32 32 32 33 33 34 6.1 6.2 6.3 Downhole Flow Check Assembly General CT Bottomhole Assembly (BHA) Connectors Downhole Flow Check Devices 34 34 34 34 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 Elastomers and Seals General Rapid Gas Decompression (RGD) Chemical Compatibility Temperature Performance Range Extrusion Resistance Abrasion/Erosion Resistance Pressure Rating Other Considerations 35 35 35 36 36 36 37 37 37 8.1 8.2 8.3 Choke Manifolds and Choke Lines Purpose Choke Line Installation Choke Manifold Installation 38 38 38 38 Kill Lines 9.1 Purpose 9.2 Kill Line Installation 9.3 Bleed-off Lines 40 40 40 42 10 10.1 10.2 10.3 10.4 Pump Lines Purpose Pump Line(s) Installation Reel Swivel Bleed-off Lines 42 42 42 44 44 11 General Description of CT Surface Equipment 45 v Page 11.1 11.2 11.3 11.4 11.5 11.6 11.7 General Typical CT Unit Components Injector Tubing Guide Arch Reel Power Supply/Prime Mover Monitoring Equipment 45 45 46 49 50 51 51 12 12.1 12.2 12.3 12.4 12.5 12.6 12.7 Well Control Equipment Testing General Performance Testing—Slip and Shear Rams Performance Load Test—Flow Check Assembly Connector Pressure Testing Test Documentation General Testing Considerations Pressure Test Devices 51 51 51 53 53 55 55 55 13 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 Well Control Equipment Operating System General Functional Requirements Well Control Equipment Operating System Components Reservoir Pump System and Pump Sizing Accumulator Bank and Accumulator Sizing Control Panel and Manifold Hydraulic Control Fluid 56 56 56 56 57 56 57 58 59 14 14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 Pre-job Planning and Preparation General Well Control Contingencies Job Planning Location—Equipment Layout Personnel Requirements Job Review Equipment Rig-up Considerations CT Service Considerations 59 59 59 59 61 62 62 63 63 Annex A (informative) Accumulator Sizing Calculations 64 Annex B (informative) CT Well Control Contingencies and Drills 68 Bibliography 75 Figures Well Control Stack Components for PC-0 Conditions—for Returns Taken Through the Tree or Wellhead Below the Well Control Stack Well Control Stack Components for PC-0 Condition—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Well Control Stack Components for PC-1 Conditions (1 psig to 1500 psig)—for Returns Taken Through the Tree or Wellhead Below the Well Control Stack Well Control Stack Components for PC-1 Conditions (1 psig to 1500 psig)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Well Control Stack Components for PC-2 Conditions (1501 psig to 3500 psig)—for Returns Taken Through the Tree or Wellhead Below the Well Control Stack 14 15 16 17 19 Page 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 Well Control Stack Components for PC-2 Conditions (1501 psig to 3500 psig)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Well Control Stack Components for PC-3 Conditions (3501 psig to 7500 psig)—for Returns Taken Through the Tree or Wellhead Below the Well Control Stack Well Control Stack Components for PC-3 Conditions (3501 psig to 7500 psig)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Well Control Stack Components for PC-4 Conditions (7501 psig to 12,500 psig)—for Returns Taken Through the Tree or Wellhead Below the Well Control Stack Well Control Stack Components for PC-4 Conditions (7501 psig to 12,500 psig)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Blind Ram Pipe Rams Shear Rams Slip Rams Shear-blind Combination Rams Pipe-slip Combination Rams Single Inline Choke Installation (PC-1 and PC-2)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Single Inline Choke Installation (PC-3)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Single Inline Choke Installation (PC-4)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Dual Choke Manifold Installation (PC-1 and PC-2)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Dual Choke Manifold Installation (PC-3)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Dual Choke Manifold Installation (PC-4)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Dual Choke Manifold Installation (PC-1 and PC-2)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Dual Choke Manifold Installation (PC-3)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Dual Choke Manifold Installation (PC-4)—for Returns Taken Through the Flow Cross or Flow Tee Installed in the Well Control Stack Kill Line Installation (All PC Conditions) Tables Pressure Categories for CT Well Control Equipment Example Collapse Width Predictions and Minimum Stack Bore Size for CT B.1 Personnel Actions to Address a Stripper Assembly Leak B.2 Personnel Actions to Address a Leak Between the Tubing Guide Arch and Service Reel B.3 Personnel Actions to Address a Leak Between the Tubing Guide Arch and Stripper Assembly B.4 Personnel Actions to Address a Separation Failure Between the Tubing Guide Arch and Service Reel B.5 Personnel Actions to Address a Tensile Separation Failure Between the Stripper Assembly and Injector B.6 Personnel Actions to Address a Failure Between the Injector and Stripper B.7 Personnel Actions to Address a Leak Between the Surface Tree Connection and the Lowest Pressure-sealing Well Control Stack Ram Component B.8 Personnel Actions to Address a Leak Between the Stripper Assembly and Pipe Ram Component 20 21 22 24 25 26 27 28 29 30 30 39 40 41 42 43 44 45 46 47 48 12 34 68 69 70 71 71 72 73 74 Introduction This recommended practice is provided to meet the need for assembly and operation of coiled tubing well control equipment Coiled tubing well control typically relies on mechanical barriers as the primary means of well control vi 66 API RECOMMENDED PRACTICE 16ST where Pmax is the minimum required accumulator bank pressure as defined in A.1.3.4 (psia); ρ@Pcrit is the nitrogen density at Pcrit and minimum operating temperature or the pre-charge temperature, whichever is the least (lbm/ft3); ρ@Pmax is the maximum operating temperature (°R); Z@Pmax is the compressibility factor of nitrogen at Pmax and Tmax The conversion factors for pressure and temperature are shown as follows: a) absolute pressure (psia) is gauge pressure (psig) plus 14.7 psi, b) degrees Rankine (°R) is degrees Fahrenheit (°F) plus 460 A.1.3.5 Alternatively, Equation (A.9) can be used to calculate the density that the nitrogen in the accumulator bank will have at the minimum required pressure Pmax and temperature T@Pmax Pmax can then be determined from the data reference noted in A.1.3.4 by looking up the pressure required to cause the calculated density at the minimum anticipated operating temperature ρ @Pmax = V close ⎞ 1 – - ⎛ ρ @Pcrit ρ @Pp ⎝ V @P N A⎠ (A.9) NOTE Equation (A.7), Equation (A.8), and Equation (A.9) not take into account adiabatic cooling which occurs when the nitrogen volume expands during the ram closing functions As a result, the pressure observed at the completion of the ram component closure is expected to be less than the value calculated above A.1.3.6 If the hydraulic system operating pressure and pre-charge pressure adjustments not meet the accumulator bank pressure requirements, the nitrogen volume (V@p × NA) in the accumulator bank should be increased Since V@p is equal to the nominal accumulator(s) size, a larger accumulator or additional accumulators may provide the increase in nitrogen bladder volume desired A.1.3.7 If a shear-blind ram is also incorporated within the well control stack, the accumulator bank must also have sufficient pressure and volume to shear the CT (as defined in 12.2.3) within the respective sequence of operation In this case, the value of Pcrit for the shear-blind ram must be determined and Pmax recalculated to confirm that the shear-blind ram has sufficient pressure to effectively shear the CT at the intended point in the ram closing sequence A.1.3.8 For onsite operations, the stabilized accumulator system pressure reading of record (Pmax) shall be obtained 30 minutes after initial pressurization (to allow the accumulator bank to reach thermal equilibrium) A.2 Minimum Accumulator Volume Example Calculations A.2.1 General A well control stack system needs a volume of 10.715 gal to perform the requisite close-open-close functions of all ram components A nitrogen pre-charge of 1200 psig will be applied to the accumulators and the minimum planned charge pressure is 2950 psig The pre-charge will be performed at a temperature of 70 °F which is also the minimum anticipated operating temperature The maximum anticipated operating temperature is 100 °F COILED TUBING WELL CONTROL EQUIPMENT SYSTEMS 67 From the NIST Chemistry WebBook (http://webbook.nist.gov/chemistry/fluid): — density of nitrogen at 1200 psig and 70 °F: 5.9996 lbm/ft3 = ρ@Pp; — density of nitrogen at 1400 psig and 70 °F: 6.9659 lbm/ft3 = ρ@Pp + 200; — density of nitrogen at 2950 psig and 100 °F: 12.959 lbm/ft3 = ρ@Pmax; and, — VCOC is 10.715 gal Substituting into Equation (A.4) gives 10.715 V acc = - = 26.90 gal 1 5.9996 ⎛ – ⎞ ⎝ 6.9659 12.959⎠ (A.10) which is the minimum accumulator bank volume required to ensure a close-open-close sequence can be performed at the anticipated conditions and have 200 psi remaining in the accumulator bank For an accumulator bank using 10gal accumulators, then NA will be three or greater to meet or exceed the calculated value of Vacc A.2.2 Minimum Operating Pressure Example Calculation The volume required to close the slip, pipe and shear rams is 1.45 gal The hydraulic pressure required to shear the CT size and grade for the prescribed service at atmospheric pressure was observed to be 1800 psig The maximum anticipated surface pressure (MASP) for the given well was determined to be 6125 psig and the closing ratio of the shear ram was found to be 12.25 Using Equation (A.6), the value for Pcrit was found to be 2300 psig Pcrit = 1800 psig + (6125 psig/12.25) = 2300 psig (A.11) With a minimum required pressure of 2300 psig to shear the coiled tube (Pcrit) at MASP and a volume of 1.45 gal to close the slip, pipe and shear rams, the minimum operating pressure in the accumulator system may be found using Equation (A.9) From the NIST Chemistry WebBook (http://webbook.nist.gov/chemistry/fluid): Density of nitrogen at 2300 psig and 70 °F: 11.112 lbm/ft3 = @Pcrit ρ @Pmax = - = 12.205 lb/ft 1 ⎛ 1.45 ⎞ – 11.112 5.9996 ⎝ 10 × 3⎠ (A.12) From the data reference, the pressure required for the nitrogen to have a density of 12.205 lbm/ft3 at 70 °F is 2568.7 psia which is the minimum recommended hydraulic pressure the accumulator bank should be operated at to ensure that there is sufficient pressure available to shear the coiled tube at MASP Annex B (informative) CT Well Control Contingencies and Drills B.1 General The following are a series of equipment operation contingencies related to CT well control events The following cases are offered to provide a common sequence of expected personnel reactions to the well control events described for use in well control drills and training for non-H2S service Although the following responses are considered to be typical, the appropriate emergency response shall be determined on a case-by-case basis B.2 Case A—Stripper Assembly Leak Situation: CT is deployed at a given depth within a wellbore with pressure at surface A leak is observed at the stripper assembly and additional hydraulic pressure applied to the stripper assembly does not re-establish the pressure seal See Table B.1 for the steps to follow in addressing this event Table B.1—Personnel Actions to Address a Stripper Assembly Leak Step Activity (Order may vary according to circumstances) CT Supervisor CT Operator Pump Operator CT Helper Halt movement of CT within injector and set brake X Close slip rams and pipe rams X Assess fluid pumping activities to determine appropriate course of action Secure well as required for the operation Monitor CT pump pressure if pumping is continued Monitor wellhead pressure Assess situation to determine course of action Confirm closure of rams (report position of indicator pins) and manually lock the rams at the earliest point where safe operations permit X Bleed off trapped pressure from well control stack cavity above pipe rams X 10 Replace worn or damaged stripper assembly components X 11 Line up pump to kill line Conduct “post-repair” pressure test from below stripper assembly 12 Equalize pressure across the pipe rams Unlock pipe rams and slip rams 13 Open slip rams and pipe rams X 14 Pick up CT to locate the portion of the CT subjected to the slip ram closure above the stripper assembly and inspect for damage X 15 If damage is observed where the slip rams were set, determine the risks of continuing operations with the damaged tubing X 16 Based on the risk assessment from Step 15, either POOH or resume well servicing operations X X X X X X 68 X X COILED TUBING WELL CONTROL EQUIPMENT SYSTEMS 69 B.3 Case B—Leak in CT Between Tubing Guide Arch and Service Reel Situation: A leak is observed in the CT string between the tubing guide arch and the service reel The CT string remaining within the wellbore is capable of withstanding the tri-axial stress of the annulus fluid pressure with zero psig internal pressure present (conditions will not induce collapse of CT string) See Table B.2 for the steps to follow in addressing this event Table B.2—Personnel Actions to Address a Leak Between the Tubing Guide Arch and Service Reel Step Activity (Order may vary according to circumstances) CT Supervisor Halt movement of CT within injector and set brake Stop pumping and monitor CT pressure Secure well as required for the operation Monitor wellhead pressure Assess situation to determine course of action If there is no flow, go to Step 13 X Based on assessment, if there is sustained flow and pipe can be safely moved, go to Step 12 If there is sustained flow and the assessment concludes that pipe movement is not recommended, continue with Step X CT Operator Pump Operator CT Helper X X X X Close slip rams and pipe rams Confirm closure of rams (report position of indicator pins) and manually lock the rams at the earliest point where safe operations permit Cut the CT string using the shear rams and open shear rams Pick up CT approximately one foot with the injector to place the CT sheared end above the blind ram position X 10 Close blind rams X 11 Confirm closure of rams (report position of indicator pins) and manually lock the rams at the earliest point where safe operations permit 12 Ensure pressure is bled-off above the blind rams Go to Step 16 X 13 Pull CT string to secure the damaged tubing on the reel Step12 may be switched with Step13 depending upon the situation at hand X 14 Initiate pumping operations and displace CT with a safe liquid 15 Continue to pull CT out of the hole while monitoring well control situation X 16 Monitor well conditions and wait on instructions from company representative X X X X X B.4 Case C—Leak in CT Between Tubing Guide Arch and Stripper Assembly Situation: A leak is observed in the CT string between the tubing guide arch and the stripper assembly (within the injector body) The CT string remaining within the wellbore is capable of withstanding the tri-axial stress of the annulus fluid pressure with zero psig internal pressure present (conditions will not induce collapse of the CT string) See Table B.3 for the steps to follow in addressing this event 70 API RECOMMENDED PRACTICE 16ST Table B.3—Personnel Actions to Address a Leak Between the Tubing Guide Arch and Stripper Assembly Step Activity (Order may vary according to circumstances) CT Supervisor Halt movement of CT within injector and set brake Stop pumping and monitor CT pressure Secure well as required for the operation Monitor wellhead pressure Assess situation to determine course of action If there is no flow, go to Step 16 X Based on the assessment, if there is sustained flow and pipe can be safely moved, go to Step 13 If there is sustained flow and the assessment concludes that pipe movement is not recommended, continue with Step X CT Operator Pump Operator CT Helper X X X X Close slip rams and pipe rams Confirm closure of rams (report position of indicator pins) and manually lock the rams at the earliest point where safe operations permit Cut the CT using the shear rams and open shear rams Pick up CT approximately one foot with the injector to place the CT sheared end above the blind ram position X 10 Close blind rams X 11 Confirm closure of rams (report position of indicator pins) and manually lock the rams at the earliest point where safe operations permit 12 Ensure pressure is bled-off above the blind rams Go to Step 17 X 13 Run the CT in the well to position the leak below the stripper assembly and above the pipe rams X 14 Close slip rams and pipe rams X 15 Confirm closure of rams (report position of indicator pins) and manually lock the rams at the earliest point where safe operations permit 16 Initiate pumping operations and displace CT with a safe liquid 17 Monitor well conditions and wait on instructions from company representative X X X X X X B.5 Case D—CT Parts Between Tubing Guide Arch and Service Reel Situation: The CT string suffers a separation failure between the tubing guide arch and the service reel The CT string segment remaining within the wellbore is capable of withstanding the tri-axial stress of the annulus fluid pressure with zero psig internal pressure present (conditions will not induce collapse of CT string) See Table B.4 for the steps to follow in addressing this event B.6 Case E—CT Parts Between Stripper Assembly and Injector Situation: The CT string suffers a tensile separation failure between the stripper assembly and the injector chain drive section The following sequence applies if the tubing is considered sufficiently off-bottom to allow for tubing to fall below the christmas tree and the separated tubing segment cannot be controlled with the injector If the CT is still controlled by the injector, refer to B.5, Case D See Table B.5 for the steps to follow in addressing this event COILED TUBING WELL CONTROL EQUIPMENT SYSTEMS 71 Table B.4—Personnel Actions to Address a Separation Failure Between the Tubing Guide Arch and Service Reel Step Activity (Order may vary according to circumstances) CT Supervisor CT Operator Halt movement of CT within injector and set brake Stop pumping operations through CT Secure well as required for the operation Close the slip rams and pipe rams Confirm closure of rams (report position of indicator pins) and manually lock rams at the earliest point where safe operations permit Set reel brake on service reel Assess situation to determine course of action X If the downhole flow check device(s) are holding pressure (no flow through the CT at surface), go to Step 14 X If the flow check device(s) are leaking, cut the CT using the shear rams and open shear rams X Pick up CT approximately one foot with the injector to place the CT sheared end above the blind ram position X 10 Close blind rams X 11 Monitor and compare the pressures above the blind rams, at the kill spool, and at the choke or flow tee 12 Confirm closure of rams (report position of indicator pins) and manually lock rams at the earliest point where safe operations permit 13 Ensure that pressure is bled off above the blind ram 14 Secure spooled segment of CT to reel 15 Monitor well conditions and wait on instructions from company representative Pump Operator CT Helper X X X X X X X X X X Table B.5—Personnel Actions to Address a Tensile Separation Failure Between the Stripper Assembly and Injector Step Activity (Order may vary according to circumstances) Halt movement of CT within injector and set brake Stop pumping operations through CT Secure well as required for the operation Assess situation to determine course of action (confirm reduction in weight indicator reading) When separated CT segment falls below the blind rams, close blind rams Close christmas tree valve Count number of valve handle turns to confirm proper closure Set reel brake on service reel Monitor well conditions and wait on instructions from company representative CT Supervisor CT Operator Pump Operator CT Helper X X X X X X X 72 API RECOMMENDED PRACTICE 16ST B.7 Case F—CT Buckle Between Injector and Stripper Assembly (Shear-blind Ram Present) Situation: The CT failed between the injector and the stripper through catastrophic buckling due to excessive thrust load The tubing may be mechanically stuck within the well and may not be able to clear the stripper Upon pick-up, the tubing may suffer a separation failure NOTE There is no recommended solution for this condition without the use of a shear-blind ram See Table B.6 for the steps to follow in addressing this event Table B.6—Personnel Actions to Address a Failure Between the Injector and Stripper Step Activity (Order may vary according to circumstances) CT Supervisor CT Operator Pump Operator CT Helper Halt movement of CT within injector and set brake Stop pumping and monitor CT pressure X Close the slip rams and pipe rams X Increase stripper assembly pressure X Secure the well as required for the operation Assess situation to determine course of action If no external leaks are observed, go to Step X If there is a leak above the stripper assembly, cut the CT string using the shear-blind rams X Attempt to close the christmas tree valve and secure the well Count the number of valve handle turns to confirm proper closure X Confirm closure of rams (report position of indicator pins) and manually lock rams at the earliest point where safe operations permit X 10 Monitor well conditions and wait on instructions from company representative X X X B.8 Case G—Leak Between Tree and Well Control Stack Pressure-sealing Rams Situation: A leak is observed in the well control stack components between the surface tree connection and the lowest pressure-sealing well control stack ram component CT is currently deployed at a given off-bottom depth within a wellbore completed in a hydrocarbon-bearing reservoir and continued flow from the well will transport hydrocarbons to the surface See Table B.7 for the steps to follow in addressing this event B.9 Case H—Leak Between Stripper and Well Control Stack Rams Situation: A leak is observed in the well control stack components between the stripper assembly and the pipe ram component CT is currently deployed at a given depth within a wellbore completed in a hydrocarbon-bearing reservoir and continued flow from the well will transport hydrocarbons to the surface See Table B.8 for the steps to follow in addressing this event COILED TUBING WELL CONTROL EQUIPMENT SYSTEMS 73 Table B.7—Personnel Actions to Address a Leak Between the Surface Tree Connection and the Lowest Pressure-sealing Well Control Stack Ram Component Step Activity (Order may vary according to circumstances) CT Supervisor CT Operator Halt movement of CT within injector and set brake Assess situation to determine course of action X Assess fluid pumping activities to determine appropriate course of action X Monitor CT pump pressure (if continued) Monitor wellhead pressure Secure well as required for the operation Consult with company representative to determine if it is safe to pull CT out of the hole or if emergency well control practices should be implemented If well can be safely killed, go to Step 15 If safe to pull CT out of hole, go to Step 19 If options above are unacceptable, go to Step X Confirm that CT has room to fall below the wellhead within the wellbore and prepare for emergency “shear & drop” procedure X Close the slip rams and pipe rams 10 Cut the CT using the shear rams and open the shear rams 11 Pick up CT approximately one foot to place CT sheared end above the blind ram position X 12 Close blind ram X 13 Open the pipe rams and slip rams and allow CT string to fall into the wellbore X 14 Close christmas tree valve Count number of valve handle turns to confirm proper closure Go to Step 21 15 Determine appropriate fluid kill program and prepare to implement 16 Line up pump(s) and kill fluids 17 Conduct pumped fluid kill program X 18 Complete kill program Proceed to Step 21 X 19 Initiate CT retrieval activities and pull the CT string out of the hole 20 Close the christmas tree valve and secure the well Count number of valve handle turns to confirm proper closure 21 Monitor well conditions and wait on instructions from company representative Pump Operator CT Helper X X X X X X X X X X X X 74 API RECOMMENDED PRACTICE 16ST Table B.8—Personnel Actions to Address a Leak Between the Stripper Assembly and Pipe Ram Component Step Activity (Order may vary according to circumstances) CT Supervisor CT Operator Halt movement of CT within injector and set brake X Close the pipe rams X Assess fluid pumping activities to determine appropriate course of action Secure well as required for the operation Monitor wellhead pressure Assess situation to determine course of action X Consult with the company representative to determine if it is safe to pull the CT out of the hole or if emergency well control practices should be implemented X Monitor well conditions and wait on instructions from company representative X Pump Operator CT Helper X X X Bibliography [1] API Bulletin 6J, Testing of Oilfield Elastomers (a Tutorial) [2] API Specification 11IW, Specification for Independent Wellhead Equipment [3] API Recommended Practice 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, 5th Edition [4] NIST Chemistry WebBook 3 National Institute of Standards and Technology, 100 Bureau Drive, Stop 3460, Gaithersburg, Maryland 20899, www.nist.gov 75 THERE’S MORE WHERE THIS CAME FROM API provides additional resources and programs to the oil and natural gas industry which are based on API Standards For more information, contact: API MONOGRAM® LICENSING PROGRAM Phone: 202-962-4791 Fax: 202-682-8070 Email: certification@api.org API INDIVIDUAL CERTIFICATION PROGRAMS (ICP®) Phone: 202-682-8064 Fax: 202-682-8348 Email: icp@api.org API QUALITY REGISTRAR (APIQR®) API ENGINE OIL LICENSING AND CERTIFICATION SYSTEM (EOLCS) Phone: 202-682-8516 Fax: 202-962-4739 Email: eolcs@api.org > ISO 9001 Registration > ISO/TS 29001 Registration > ISO 14001 Registration > API Spec Q1® Registration Phone: 202-962-4791 Fax: 202-682-8070 Email: certification@api.org API 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