Api rp 59 2006 (2012) (american petroleum institute)

Recommended Practice for Well Control Operations API RECOMMENDED PRACTICE 59 SECOND EDITION, MAY 2006 REAFFIRMED, JANUARY 2012 Recommended Practice for Well Control Operations Upstream Segment API RECOMMENDED PRACTICE 59 SECOND EDITION, MAY 2006 REAFFIRMED, JANUARY 2012 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 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, 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 © 2006 American Petroleum Institute FOREWORD This publicaiton is under jurisdiction of the American Petroleum Institute, Upstream Department’s Executive Committee on Drilling and Production Operations Drilling and well service unit (production well service, well workover, well completion, and plug and abandonment) operations are being conducted with full regard for personnel safety, public safety, and preservation of the environment in such diverse conditions as metropolitan sites, wilderness areas, ocean platforms, deepwater sites, barren deserts, wildlife refuges, and arctic ice packs Recommendations presented in this publication are based on extensive and wide-ranging industry experience The goal of this voluntary recommended practice is to assist the oil and gas industry in promoting personnel and public safety, integrity of the drilling and well service equipment, and preservation of the environment for land and marine drilling and well service operations This recommended practice is published to facilitate the broad availability of proven, sound engineering and operating practices This publication does not present all of the operating practices that can be employed to successfully install and operate well control systems in drilling and well service operations Nor does this publication imply that all of the practices herein are applicable to all drilling and well service operations Drilling and well service operations throughout the world vary widely and take place under a wide range of downhole and surface conditions Practices at one operation will not necessarily be required at a similar operation due to different conditions Practices set forth herein are considered acceptable for accomplishing the job as described; equivalent alternative installations and practices may be utilized to accomplish the same objectives Individuals and organizations using these recommended practices are cautioned that operations must comply with requirements of national, state, or local regulations These requirements should be reviewed to determine whether violations may occur Users of recommendations set forth herein are reminded that constantly developing technology and specialized or limited operations not permit complete coverage of all operations and alternatives Recommendations presented herein are not intended to inhibit developing technology and equipment improvements or improved operational procedures These recommended practices are not intended to obviate the need for qualified engineering and operations analyses and sound judgments as to when and where these recommended practices should be utilized to fit a specific drilling application This publication includes use of the verbs shall and should, whichever is deemed most applicable for the specific situation For the purposes of this publication, the following definitions are applicable: Shall—Indicates that the recommended practice(s) has universal applicability to that specific activity Should—Denotes a recommended practice(s) a) where a safe comparable alternative practice(s) is available; b) that may be impractical under certain circumstances; or c) that may be unnecessary under certain circumstances or applications Changes in the uses of these verbs are not to be effected without risk of changing the intent of recommendations set forth herein 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 This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API staniii dard 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 and updated quarterly by API, 1220 L Street, N.W., Washington, D.C 20005 Suggested revisions are invited and should be submitted to the Standards and Publications Department, API, 1220 L Street, NW, Washington, DC 20005, standards@api.org iv CONTENTS Page SCOPE 1.1 Purpose .1 1.2 BOP Installations 1.3 Operations 1.4 Furthering the Understanding of Well Control 1.5 Deepwater REFERENCES 2.1 Standards 2.2 Other References GLOSSARY FOR WELL CONTROL OPERATIONS 3.1 Definitions 3.2 Acronyms and Abbreviations PRINCIPLES OF WELL CONTROL 4.1 General 4.2 Conventions 4.3 Primary Well Control .7 4.4 The Flowing Well 4.5 Drilling or Workover Fluid 4.6 Influx Behavior 10 4.7 Formation Integrity Tests .10 4.8 Well Control Pressures .11 4.9 Well Close-in Procedures .14 4.10 Methods For Circulating Kicks At Constant Bottom-Hole Pressure 15 4.11 Non-Circulation Kill Methods 23 4.12 Comparison of Kill Methods 25 4.13 Choke Line Pressure—Subsea Stacks 26 4.14 Diverter Systems Applications .31 4.15 Well Control Worksheets 31 CAUSES OF KICKS .32 5.1 Conditions Necessary for a Kick .32 5.2 Insufficient Hydrostatic Pressure .32 5.3 Drilling Into an Adjacent Well 33 WELL CONTROL WARNING SIGNALS 33 6.1 General 33 6.2 Gain in Pit Volume .33 6.3 Increased Flow from Annulus 33 6.4 Volume of Drilling Fluid to Keep the Hole Full on a Trip is Less Than Calculated or Less Than Trip Book Record 33 6.5 Sudden Increase in Bit Penetration Rate 34 6.6 Change in Pump Speed or Pressure .34 6.7 Flow After Pumps Stopped 34 6.8 Gas-cut Drilling Fluid 34 6.9 Liquid-cut Drilling Fluid 35 v CONTENTS Page WELL PLANNING .35 7.1 Introduction 35 7.2 Data Availability and Gathering 35 7.3 Shallow Flows 36 7.4 Casing .37 7.5 Cementing 37 7.6 Blowout Prevention Equipment Selection 37 7.7 Drilling Fluid 38 7.8 Service Operations .38 7.9 Kick Response Plans 39 7.10 Riser Disconnect .39 7.11 Simultaneous Operations 39 7.12 Logistics 39 7.13 Safety and Medical 40 7.14 Communication 40 7.15 Training and Instruction 40 WELL CONTROL PROCEDURES FOR SURFACE DIVERTER INSTALLATIONS 41 8.1 Purpose .41 8.2 Installation of Equipment 41 8.3 Diverter Operation 41 8.4 Diverter Stripping Operations 42 CONTROL PROCEDURES—SURFACE BOPS 42 9.1 Pre-kick Planning .42 9.2 Well Control Procedures 43 9.3 Drill String Off-bottom 44 9.4 High-Angle and Horizontal Well Bores 45 9.5 Reference Notes For Section 45 10 WELL CONTROL PROCEDURES FOR SUBSEA BOPS 46 10.1 General 46 10.2 Additional Causes of Kicks Unique to Subsea Operations 46 10.3 Subsea Exceptions to Control Procedures 46 10.4 Special Subsea Procedures 47 11 WELL CONTROL PROCEDURES—RECOMMENDED RIG PRACTICES 48 11.1 Well Control System Equipment Installation .48 11.2 Well Control Equipment Installation Test 49 11.3 Crew Drills 49 11.4 Trip Tanks 50 11.5 Gas-Cut Drilling Fluid 50 11.6 Trip Book 50 11.7 Pre-Kick Information 52 11.8 Minimize Time Out of the Hole 52 11.9 Trip Margin 52 11.10 Short Trip 52 11.11 Rig Practices for Handling Pressure .54 CONTENTS Page 11.12 Rig Practices for Pipe Handling 54 11.13 Drill Stem Tests .54 12 PROCEDURES FOR DEALING WITH SPECIAL PROBLEMS 54 12.1 Introduction .54 12.2 Pump Failure in a Kick Situation 55 12.3 Excessive Casing Pressure 55 12.4 Pipe Problems with a Well Kick .56 12.5 Procedures for Gas Bubble Migration 59 12.6 Gas Influx In Cemented Annulus .59 12.7 Drill Stem Testing .60 12.8 Stripping Procedures .60 12.9 Bullheading and Top Kill Methods 61 13 SLURRIES AND PLUGS TO DEAL WITH LOST CIRCULATION AND UNDERGROUND BLOWOUTS 61 13.1 Introduction .61 13.2 Lost Circulation 61 13.3 Underground Blowouts 61 13.4 Barite Plugs .62 13.5 Squeeze Slurries 64 APPENDIX A KICK PRESSURE AND GRADIENT CALCULATIONS 67 APPENDIX B WELL CONTROL WORKSHEETS 77 Figures 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16 4.17 4.18 4.19 4.20 11.1 A.1 A.2 Example of Primary Well Control Conditions Well Performance Equipment Performance Relationship Equipment & Well Performance Curves Dynamic Kil Static Well Kick Pressures 12 Equivalent Circulating Density 13 Well Closed-In on a Kick 14 Closed-In Drill Pipe Pressure 14 Gas Influx Migrating Up The Hole 15 Stabilized Pumping of A Kick 17 Casing Pressure And Gas Volume Resulting From Using The Driller’s Method 19 Casing Pressure and Gas Volume Using the Driller’s Method 20 Drill Pipe Pressure Schedule for the Wait and Weight Method 21 Typical Casing Pressure Resulting from Using Wait and Weight Method 22 Drill Pipe Pressure Schedule-Concurrent Method 24 Typical Casing Pressure Resulting From Using Concurrent Method 25 Example Of Approximate Casing Pressures With Different Kill Methods 27 Pressure Loss versus Flow Rate 28 Pressure Loss through Choke Line and Manifold With Choke Full Open 29 Loss of Effective Drilling Fluid Density Due to Gas Cut 51 Weight of a Gas Kick, 0.6 Gravity Gas 69 Maximum Surface Pressure of A Zero Intensity Gas Kick 70 CONTENTS Page A.3 Factor for Determining the Maximum Surface or Casing Shoe Pressure while Killing a Gas Kick with a Constant Bottom-Hole Pressure Method 71 Tables 11.1 12.1 13.1 13.2 13.3 13.4 13.5 13.6 Example Form from a Trip Book Indicators of Possible Problems while Circulating Out a Kick Barite Slurry Formulations Slurry Volumes Barite Required (API Barite Specific Gravity = 4.20) Diesel Oil-Bentonite Drilling Fluid Reactive Slurries Trial Mixing Ratios for Reactive Slurry Mixtures Materials Quantities for Mixing One Barrel of HWL-HS Cement Slurry 53 57 62 63 63 63 65 66 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET DRILLERS METHOD DATE RIG CALCULATIONS AND NOTES PROCEDURE I PRERECORDED INFORMATION (1) A Fracture Drilling Fluid Density Casing: Size _ in., Weight lb/ft, Grade , Internal Yield psi, Depth (TVD) ft Mechanical Pressure Limit psi Casing Pressure to Cause Fracture psi (1), based on present drilling fluid density of lb/gal Maximum Allowable Casing Pressure: Initial Closure psi Approved by: Entire Well Kill _ psi (Name) Contingency Procedure (2) if casing pressure reaches maximum approved: _ _ Normal Circulating Pressure and Rate: psi at stks/min and bpm* at _ lb/gal and _ ft Kill Pressure and Rate: Pump No , psi at stks/min and bpm* at _ lb/gal and _ ft (3) Pump No , psi at stks/min and bpm* at _ lb/gal and _ ft (3) Drill Pipe Capacity: bbl/ft = IV V + lb/gal = _ lb/gal .052 x _ ft B Fracture Pressure = 052 x Casing Depth x (Fracture Drilling Fluid Density – Present Drilling Fluid Density) = 052 x _ ft x ( lb/gal – _ lb/gal) = psi (2) If casing pressure reaches maximum allowed, follow the Contingency Procedure (3) Measure daily while drilling or after a significant change in circulating system pressure (4) Calculated Initial Circulating Pressure = Kill Rate Pressure plus Closed-in Drill Pipe Pressure = _ psi + psi = psi = Closed-in Drill Pipe Pressure 052 x Bit Depth (TVD) ESTABLISH CIRCULATION Open choke while bringing pump up to Kill Rate Increase pump rate slowly, if possible Adjust choke to hold Casing Pressure constant at closed-in value while bringing pump to Kill Rate Hold Kill Rate constant The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure (4) When approximately equal, use the choke to adjust the observed drill pipe pressure to the calculated pressure If widely divergent, close in the well and consider alternatives Record time when circulation started hrs (5) Required Drilling Fluid Density CIRCULATE OUT THE KICK (6) While holding Kill Rate constant, keep Drill Pipe Pressure constant by adjusting choke If Drill Pipe Pressure increases, open choke If Drill Pipe Pressure decreases, close choke Casing Pressure must be allowed to vary to maintain constant bottom-hole pressure When well is free of gas, salt water, and oil, stop pump and close choke Record New Closed-in Casing Pressure psi If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole (7) Circulating Time To Bit _ psi = = INCREASE DRILLING FLUID DENSITY (8) Establish circulation as per item III, using New Closed-in casing Pressure plus 100 psi † Hold Kill Rate constant and hold New Casing Pressure constant by adjusting the choke Maintain required drilling fluid density in pits while circulating Circulate heavy drilling fluid to bit as determined by time or strokes (7) (8) When heavy drilling fluid reaches bit, read and record Final Drill Pipe Circulating Pressure psi Hold Final Drill Pipe Pressure constant by varying choke while holding Kill Rate constant After uncut heavy drilling fluid reaches the surface, shut down pump and check for flow + _ lb/gal + _ lb/gal † = lb/gal Drill Pipe Capacity x Drill String Length Kill Rate bbl/ft x _ ft = CIRCULATE HEAVY DRILLING FLUID + Present Drilling Fluid Density + Trip Margin † 052 x ft Calculate the Required Drilling Fluid Density (5) and increase fluid density in the suction pit (6) VI + Leak-off Test Drilling Fluid Density IMMEDIATE ACTION When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe casing pressure] Do not exceed Maximum Allowable Casing Pressure (2) Check for trapped pressure and record the following: Closed-in Drill Pipe Pressure psi, Casing Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl III psi = } II Leak-off Pressure 052 x Casing Depth Strokes To Bit = Kill Rate x Time = = bpm _ stks/min x _ = _ stks Notes: *Considering pump efficiency † Trip Margin and Safety Factor may be omitted, but these give little risk of loss and circulation as the open hole and casing seal are subjected to higher pressures when circulating out the kick If Trip Margin is used, when heavy drilling fluid nears the surface the choke will be wide open and the Final Drill Pipe Circulation Pressure can no longer be controlled The Drill Pipe Pressure will slowly increase to compensate for the Trip Margin Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes (over) 79 API RECOMMENDED WELL CONTROL WORKSHEET Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) DRILLERS METHOD COMPANY WELL DATE DEPTH Displacement (bbl/stk.) Where: L D d Eff Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 PREPARED BY: COMPANY _ CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 (1) (2) (3) (4) (5) Upset I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U Tool Joint Nominal (lb/ft) Approx (lb/ft) (2) Name NC No O.D in 10.40 10.40 13.30 13.30 15.50 14.00 16.60 16.60 16.60 20.00 20.00 19.50 25.60 21.90 24.70 10.28 10.76 13.40 14.77 16.39 15.85 18.98 17.81 18.37 21.62 22.09 20.89 26.89 23.77 26.33 Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H 26 31 31 38 38 46 50 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 46 50 46 50 50 (3) (3) Average Overall Joint Length, ft (4) 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 Capacity Barrels Per Foot 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 Displacement Barrels Per 3-Joint Stand 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 Feet Per Barrel 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 Barrels Per Foot (5) 0.00374 0.00392 0.00488 0.00501 0.00596 0.00577 0.00691 0.00648 0.00668 0.00786 0.00804 0.00760 0.00979 0.00865 0.00958 Barrels Per 3-Joint Stand 0.344 0.361 0.452 0.465 0.554 0.538 0.644 0.604 0.624 0.733 0.750 0.708 0.912 0.809 0.896 Barite Required = 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) = 1470 x ( _ lb/gal – lb/gal) (35 – lb/gal) = sx/100 bbl = Drilling Fluid Volume x Sacks/100 bbl 100 = bbl x _ sx/100 bbl 100 Required Mixing Rate = = = Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 (100 Percent Volumetric Efficiency) Stroke Length, in 7 7 7 7 8 8 = sx Sacks/100 bbl x Kill Rate _ sx/100 bbl x _ bpm = = sx/min 100 100 (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) ( _ lb/gal – _ lb/gal) x bbl ( _ lb/gal – 8.34) Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in DILUTION OF RESERVE DRILLING FLUID WITH WATER Barrels Water Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps Grade E drill pipe Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 Obsolete tool joint Based on an average pipe length of 29.4 feet before adding tool joints The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft and volume of one barrel equal to 5.61458 ft ****** BARITE REQUIREMENTS Sacks/100 bbl Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = _ bbl 80 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET WAIT AND WEIGHT METHOD DATE RIG CALCULATIONS AND NOTES PROCEDURE I PRERECORDED INFORMATION (1) A Fracture Drilling Fluid Density Casing: Size in., Weight lb/ft, Grade , Internal Yield _ psi, Depth (TVD) ft Mechanical Pressure Limit psi Casing Pressure to Cause Fracture psi (1), based on present drilling fluid density of lb/gal Maximum Allowable Casing Pressure: Initial Closure psi Entire Well Kill _ psi Approved by: _ } = = B Fracture Pressure (Name) Contingency Procedure (2) if casing pressure reaches maximum approved: _ Normal Circulating Pressure and Rate: _ psi at stks/min and _ bpm* at lb/gal and ft Kill Pressure and Rate: Pump No , _ psi at stks/min and _ bpm* at lb/gal and _ ft (3) Pump No , _ psi at stks/min and _ bpm* at lb/gal and ft (3) Drill Pipe Capacity: bbl/ft 052 x Casing Depth x (Fracture Drilling Fluid Density – Present Drilling Fluid Density) 052 x _ ft x ( lb/gal – _ _ lb/gal) = psi = Closed-in Drill Pipe Pressure + Present Drilling Fluid Density + Trip Margin † 052 x Bit Depth (TVD) psi 052 x _ ft + _ lb/gal + lb/gal † = _ lb/gal (5) If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole (6) If drill pipe pressure increases during weighting, reduce to initial stabilized value by bleeding through the choke INCREASE DRILLING FLUID DENSITY (7) Calculated Initial Circulating Pressure PREPARE DRILL PIPE PRESSURE SCHEDULE ESTABLISH CIRCULATION (8) Final Circulating Pressure = (9) Circulating Time To Bit = = Kill Rate Pressure plus Closed-in Drill Pipe Pressure = _ psi + _ psi = _ psi Kill Rate Pressure x Required Drilling Fluid Density Original Drilling Fluid Density Drill Pipe Capacity x Drill String Length Kill Rate = = _ psi x _ lb/gal lb/gal _ bbl/ft x ft bpm = (10) Strokes To Bit = Kill Rate x Time = stks/min x = stks Open choke while bringing pump up to Kill Rate Increase pump rate slowly, if possible Adjust choke to hold Casing Pressure constant at closed-in value while bringing pump to Kill Rate Hold Kill Rate constant The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure (7) When approximately equal, use the choke to adjust the observed drill pipe pressure to the calculated pressure If widely divergent, close in the well and consider alternatives Record the drill Pipe Pressure at psi at stks/min and bpm Record time when circulation started _ hrs VI = = = Determine Initial Circulation Pressure and plot above zero time (7) Determine Final Circulating Pressure (8) and plot above Circulating Time To Bit (9) Draw a line between the points Read Drill Pipe Pressure at 5-minute intervals and record in blank spaces Calculate Strokes To Bit (10) and fill in the blanks below the drill pipe pressure schedule chart V + _ lb/gal = lb/gal IMMEDIATE ACTION Calculate the Required Drilling Fluid Density (4) and increase fluid density in the suction pit (5), (6) IV .052 x _ ft (3) Measure daily while drilling or after a significant change in circulating system pressure When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe casing pressure] Do not exceed Maximum Allowable Casing Pressure (2) Check for trapped pressure and record the following: Closed-in Drill Pipe Pressure psi, Casing Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl III psi + Leak-off Test Drilling Fluid Density (2) If casing pressure reaches maximum allowed, follow the Contingency Procedure (4) Required Drilling Fluid Density II Leak-off Pressure 052 x Casing Depth _ Notes: *Considering pump efficiency † Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes CIRCULATE HEAVY DRILLING FLUID Maintain drilling fluid density in suction pits while circulating at Kill Rate Use choke to adjust Drill Pipe Pressure to values recorded at times or strokes shown on drill pipe pressure schedule If Drill Pipe Pressure increases, open the choke; if Drill Pipe Pressure decreases, close the choke After heavy drilling fluid reaches bit (9) (10), hold Drill Pipe Pressure constant until uncut drilling fluid of required density reaches the surface Stop circulation and check for flow (over) 81 = _ psi API RECOMMENDED WELL CONTROL WORKSHEET Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) Displacement (bbl/stk.) Where: L D d Eff WAIT AND WEIGHT METHOD COMPANY WELL DATE DEPTH Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 PREPARED BY: COMPANY CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 Capacity Tool Joint Nominal (lb/ft) Approx (lb/ft) (2) Name Upset NC No I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U 10.40 10.40 13.30 13.30 15.50 14.00 16.60 16.60 16.60 20.00 20.00 19.50 25.60 21.90 24.70 10.28 10.76 13.40 14.77 16.39 15.85 18.98 17.81 18.37 21.62 22.09 20.89 26.89 23.77 26.33 Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H 26 31 31 38 38 46 50 Average Overall Joint O.D., Length, ft (4) in 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 46 50 46 50 50 (3) (3) Barrels Per Foot 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 Barrels Per 3-Joint Stand 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 Displacement Feet Per Barrel 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 Barrels Per Foot (5) 0.00374 0.00392 0.00488 0.00501 0.00596 0.00577 0.00691 0.00648 0.00668 0.00786 0.00804 0.00760 0.00979 0.00865 0.00958 Barrels Per 3-Joint Stand 0.344 0.361 0.452 0.465 0.554 0.538 0.644 0.604 0.624 0.733 0.750 0.708 0.912 0.809 0.896 = 1470 x ( lb/gal – lb/gal) (35 – lb/gal) = = Drilling Fluid Volume x Sacks/100 bbl 100 = bbl x _ sx/100 bbl 100 = _ sx Required Rate = Sacks/100 bbl x Kill Rate 100 = sx/100 bbl x _ bpm 100 = sx/min Mixing Stroke Length, in 7 7 7 7 8 8 DILUTION OF RESERVE DRILLING FLUID WITH WATER Barrels Water = = (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) ( _ lb/gal – _ lb/gal) x bbl ( lb/gal – 8.34) Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 sx/100 bbl Barite Required Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 (100 Percent Volumetric Efficiency) ****************** 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in BARITE REQUIREMENTS = Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps (1) Grade E drill pipe (2) Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 (3) Obsolete tool joint (4) Based on an average pipe length of 29.4 feet before adding tool joints (5) The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft3 and volume of one barrel equal to 5.61458 ft Sacks/100 bbl Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = _ bbl 82 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET CONCURRENT METHOD DATE RIG CALCULATIONS AND NOTES PROCEDURE I PRERECORDED INFORMATION Casing: Size _ in., Weight _ lb/ft, Grade _ , Internal Yield _ psi, Depth (TVD) ft Mechanical Pressure Limit psi Casing Pressure to Cause Fracture psi (1), based on present drilling fluid density of lb/gal Maximum Allowable Casing Pressure: Initial Closure psi Entire Well Kill _ psi Approved by: } (Name) IMMEDIATE ACTION When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe casing pressure] Do not exceed Maximum Allowable Casing Pressure (2) Check for trapped pressure and record the following: Closed-in Drill Pipe Pressure psi, Casing Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl III ESTABLISH CIRCULATION Open choke while bringing pump up to Kill Rate Increase pump rate slowly, if possible Adjust choke to hold Casing Pressure constant at closed-in value while bringing pump to Kill Rate Hold Kill Rate constant The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure (4) When approximately equal, use the choke to adjust the observed Drill Pipe Pressure to the calculated pressure If widely divergent, close the well and consider alternatives Record time when circulation started hrs IV = 052 x ft x ( lb/gal – lb/gal) = psi (3) Measure daily while drilling or after a significant change in circulating system pressure (4) Calculated Initial Circulating Pressure = Kill Rate Pressure plus Closed-in Drill Pipe Pressure = _ psi + psi = psi (5) If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole (6) Required Drilling Fluid Density = = Closed-in Drill Pipe Pressure 052 x Bit Depth (TVD) _ psi 052 x ft + Present Drilling Fluid Density + Trip Margin † + lb/gal + 0.3 lb/gal † = lb/gal Required Drilling Fluid Density Original Drilling Fluid Density (7) Final Circulating Pressure = Kill Rate Pressure x (8) Circulating Time To Bit = Drill Pipe Capacity x Drill String Length = Kill Rate PREPARE DRILL PIPE PRESSURE SCHEDULE Fill in bottom of graph with even increments of drilling fluid density from Initial to Required Drilling Fluid Density Plot Initial Circulating Pressure (4) above Initial Drilling Fluid Density Determine Final Circulating Pressure (7) and plot above Required Drilling Fluid Density (6) Draw a line between the points Read Drill Pipe Pressure at each increment of drilling fluid density and record in blank spaces Calculate Circulating Time (8) (or strokes) (9) to Bit Fill blank spaces with /2 Circulating Time (or strokes) to Bit Add /2 Circulating Time (or strokes) to Bit to time (or strokes) for each drilling fluid density increment VI = 052 x Casing Depth x (Fracture Drilling Fluid Density – Present Drilling Fluid Density) = _ psi x bbl/ft x ft bpm _ lb/gal _ lb/gal = _ psi = (9) Strokes To Bit = Kill Rate x Time = _ stks/min x = stks Notes:*Considering pump efficiency † Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes INCREASE DRILLING FLUID DENSITY Record time or strokes at which fluid in the suction pit is increased each 0.1 or 0.2 lb/gal on graph (5) Calculate Required Drilling Fluid Density (6) V B Fracture Pressure (2) If casing pressure reaches maximum allowed, follow the Contingency Procedure Contingency Procedure (2) if casing pressure reaches maximum approved: _ Normal Circulating Pressure and Rate: psi at _ stks/min and bpm* at lb/gal and ft Kill Pressure and Rate: Pump No , _ psi at _ stks/min and bpm* at lb/gal and ft (3) Pump No , _ psi at _ stks/min and bpm* at lb/gal and ft (3) Drill Pipe Capacity: bbl/ft II Leak-off Pressure _ psi (1) A Fracture Drilling Fluid Density = + Leak-off Test Drilling Fluid Density = + _ lb/gal = _ lb/gal .052 x Casing Depth 052 x ft KILLING THE WELL Hold Drill Pipe Pressures shown for each drilling fluid density increment at times (or strokes) shown by adjusting choke, while holding Kill Rate constant After Required Drilling Fluid Density (6) reaches the bit, hold Final Circulating Pressure (7) constant until uncut drilling fluid of required drilling density reaches surface, stop circulating and check for flow (over) 83 API RECOMMENDED WELL CONTROL WORKSHEET Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) Displacement (bbl/stk.) Where: L D d Eff CONCURRENT METHOD COMPANY WELL DATE DEPTH Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 PREPARED BY: _ COMPANY _ CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 Upset I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U Nominal (lb/ft) 10.40 10.40 13.30 13.30 15.50 14.00 16.60 16.60 16.60 20.00 20.00 19.50 25.60 21.90 24.70 Capacity Tool Joint Approx (lb/ft) (2) 10.28 10.76 13.40 14.77 16.39 15.85 18.98 17.81 18.37 21.62 22.09 20.89 26.89 23.77 26.33 Name Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H NC No 26 31 31 38 38 46 50 46 50 46 50 50 (3) (3) O.D., in 3 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 Average Overall Joint Length, ft (4) 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 Barrels Per Foot 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 Barrels Per 3-Joint Stand 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 Displacement Feet Per Barrel 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 Barrels Per Foot (5) 0.00374 0.00392 0.00488 0.00501 0.00596 0.00577 0.00691 0.00648 0.00668 0.00786 0.00804 0.00760 0.00979 0.00865 0.00958 Barrels Per 3-Joint Stand 0.344 0.361 0.452 0.465 0.554 0.538 0.644 0.604 0.624 0.733 0.750 0.708 0.912 0.809 0.896 = 1470 x ( lb/gal – lb/gal) (35 – lb/gal) Barite Required = Drilling Fluid Volume x Sacks/100 bbl 100 Required Mixing Rate = Sacks/100 bbl x Kill Rate 100 = Stroke Length, in 7 7 7 7 8 8 bbl x sx/100 bbl = _ sx 100 _ sx/100 bbl x bpm 100 = _ sx/min DILUTION OF RESERVE DRILLING FLUID WITH WATER Barrels Water = (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) = ( lb/gal – lb/gal) x _ bbl ( _ lb/gal – 8.34) Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 = sx/100 bbl = Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 (100 Percent Volumetric Efficiency) BARITE REQUIREMENTS = Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in ****************** Sacks/100 bbl Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps (1) Grade E drill pipe (2) Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 (3) Obsolete tool joint (4) Based on an average pipe length of 29.4 feet before adding tool joints (5) The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft3 and volume of one barrel equal to 5.61458 ft 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = _ bbl 84 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET WAIT AND WEIGHT METHOD DATE RIG (SUBSEA STACK) CALCULATIONS AND NOTES PROCEDURE I PRERECORDED INFORMATION (1) A Fracture Drilling Fluid Density = Casing: Size in., Weight lb/ft, Grade , Internal Yield psi, Depth (TVD) ft Mechanical Pressure Limit psi Casing Pressure to Cause Fracture psi (1), based on present drilling fluid density of lb/gal Maximum Allowable Casing Pressure: Initial Closure _ psi Entire Well Kill psi Approved by: } Leak-off Pressure 052 x Casing Depth _ psi = + Leak-off Test Drilling Fluid Density + lb/gal = lb/gal .052 x _ ft B Fracture Pressure (Name) = 052 x Casing Depth x (Fracture Drilling Fluid Density – Present Drilling Fluid Density) = 052 x ft x ( lb/gal – _ lb/gal) = psi (2) If casing pressure reaches maximum allowed, follow the Contingency Procedure Contingency Procedure (2) if casing pressure reaches maximum approved: _ (3) Measure daily while drilling or after a significant change in circulating system pressure (4) Choke Line Pressure (measure by circulating at the Kill Rate through the choke manifold down the choke line and up the riser) Normal Circulating Pressure and Rate: _ psi at _ stks/min and bpm* at _ lb/gal and _ ft Kill Pressure and Rate: Pump No , _ psi at stks/min and bpm* at _ lb/gal and _ ft (3) Pump No , _ psi at stks/min and bpm* at _ lb/gal and _ ft (3) Drill Pipe Capacity: bbl/ft, Choke Line Pressure at Kill Rate _ psi at bpm and lb/gal (4) II psi 052 x _ ft + Present Drilling Fluid Density + Trip Margin † + _ lb/gal + 0.3 lb/gal † = lb/gal (7) If drill pipe pressure increases during weighting, reduce to initial stabilized value by bleeding casing pressure through the choke = Kill Rate Pressure plus Closed-in Drill Pipe Pressure (8) Calculated Initial Circulating Pressure = _ psi + _ psi = _ psi (9) Final Circulating Pressure = Kill Rate Pressure x (10) Circulating Time To Bit = Required Drilling Fluid Density Original Drilling Fluid Density Drill Pipe Capacity x Drill String Length = Kill Rate = _ psi x _ bbl/ft x ft bpm _ lb/gal _ lb/gal = psi = (11) Strokes To Bit = Kill Rate x Time = stks/min x = stks (12) Corrected Choke Line Pressure = ESTABLISH CIRCULATION Open the kill line to a pressure gauge Slowly open the choke controlling the choke line and make adjustments as necessary to hold the kill line pressure constant while the pump is brought up to kill rate If kill line pressure monitoring cannot be done, allow the choke manifold pressure to drop by an amount equal to the corrected choke line pressure (12) Hold Kill Rate constant The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure (8) When approximately equal, use the choke to adjust the observed Drill Pipe Pressure to the calculated pressure If widely divergent, close in the well and consider alternatives VI Closed-in Drill Pipe Pressure 052 x Depth (TVD) (6) If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole PREPARE DRILL PIPE PRESSURE SCHEDULE Determine Calculated Initial Circulation Pressure and plot above zero time (8) Determine Final Circulating Pressure (9) and plot above Circulating Time to Bit (10) Draw a line between the points Read Drill Pipe Pressure at 5-min intervals and record in blank spaces Calculate Strokes To Bit (11) and fill in the blanks below the drill pipe pressure schedule V = INCREASE DRILLING FLUID DENSITY Calculate the Required Drilling Fluid Density (5) and increase fluid density in the suction pit (6), (7) IV = IMMEDIATE ACTION When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe casing pressure] Do not exceed Maximum Allowable Casing Pressure (2) Hang off drill pipe, check for trapped pressure and record the following: Closed-in Drill Pipe Pressure psi, Casing Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl III (5) Required Drilling Fluid Density = psi x _ lb/gal lb/gal Notes:* Considering pump efficiency † Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes Omit Trip Margin if only surface casing set or drilling fluid is near fracture gradient CIRCULATE HEAVY DRILLING FLUID Maintain Drilling Fluid Density in pits while circulating at Kill Rate Use choke to adjust Drill Pipe Pressure to values recorded at times or strokes shown If Drill Pipe Pressure increases, open the choke; if Drill Pipe Pressure decreases, close the choke After heavy drilling fluid reaches bit (10), (11), hold Final Circulating Pressure constant at Kill Rate When gas reaches the choke line, sudden loss of hydrostatic pressure may result in rapid drop in Drill Pipe Pressure requiring quick choke adjustment At some time, the choke may be wide open and Drill Pipe Pressure higher than scheduled Open kill line to choke for an additional choke line, if not already open If Drill Pipe Pressure cannot be reduced using wide open choke, hold Drill Pipe Pressure constant by reducing the pump rate After uncut drilling fluid of required density reaches the surface, shut down pump and check for flow If well is dead, circulate heavy drilling fluid into riser Take steps to circulate out possible gas trapped in blowout preventers using a closed diverter If possible, continue circulating slowly through choke line while displacing riser (over) Measured Choke Line Pressure x Present Drilling Fluid Density Drilling Fluid Density When Choke Line Pressure Measured 85 = _ psi API RECOMMENDED WELL CONTROL WORKSHEET WAIT AND WEIGHT METHOD (SUBSEA STACK) COMPANY WELL DATE DEPTH Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) Displacement (bbl/stk.) Where: L D d Eff PREPARED BY: COMPANY _ Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 Upset Nominal (lb/ft) I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U 10.40 10.40 13.30 13.30 15.50 14.00 16.60 16.60 16.60 20.00 20.00 19.50 25.60 21.90 24.70 Capacity Tool Joint Approx (lb/ft) (2) 10.28 10.76 13.40 14.77 16.39 15.85 18.98 17.81 18.37 21.62 22.09 20.89 26.89 23.77 26.33 Name NC No Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H 26 31 31 38 38 46 50 46 50 46 50 50 (3) (3) Average Overall Joint O.D., Length, ft (4) in 3 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 Barrels Per Foot 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 Displacement Barrels Per 3-Joint Stand 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 Feet Per Barrel 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 Barrels Per Foot (5) 0.00374 0.00392 0.00488 0.00501 0.00596 0.00577 0.00691 0.00648 0.00668 0.00786 0.00804 0.00760 0.00979 0.00865 0.00958 Barrels Per 3-Joint Stand 0.344 0.361 0.452 0.465 0.554 0.538 0.644 0.604 0.624 0.733 0.750 0.708 0.912 0.809 0.896 Stroke Length, in 7 7 7 7 8 8 1470 x ( lb/gal – lb/gal) = sx/100 bbl (35 – lb/gal) = Drilling Fluid Volume x Sacks/100 bbl = 100 Required Mixing Rate = Barrels Water = (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) = ( _ lb/gal – _ lb/gal) x bbl ( _ lb/gal – 8.34) Sacks/100 bbl x Kill Rate 100 = _ bbl x _ sx/100 bbl 100 _ sx/100 bbl x _ bpm 100 Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) Barite Required Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 (100 Percent Volumetric Efficiency) BARITE REQUIREMENTS = Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in ****************** = Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps (1) Grade E drill pipe (2) Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 (3 Obsolete tool joint (4) Based on an average pipe length of 29.4 feet before adding tool joints (5) The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft3 and volume of one barrel equal to 5.61458 ft Sacks/100 bbl Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = _ sx = _ sx/min DILUTION OF RESERVE DRILLING FLUID WITH WATER = _ bbl 86 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET CONCURRENT METHOD DATE RIG (SUBSEA ATTACK) CALCULATIONS AND NOTES PROCEDURE I (1) A Fracture Drilling Fluid Density PRERECORDED INFORMATION = Casing: Size in., Weight lb/ft, Grade , Internal Yield psi, Depth (TVD) ft Mechanical Pressure Limit psi Casing Pressure to Cause Fracture psi (1), based on present drilling fluid density of lb/gal Maximum Allowable Casing Pressure: Initial Closure _ psi Entire Well Kill psi } III (Name) IMMEDIATE ACTION lb/gal = = 052 x Casing Depth x (Fracture Drilling Fluid Density – Present Drilling Fluid Density) (2) If casing pressure reaches maximum allowed, follow the Contingency Procedure (3) Measure daily while drilling or after a significant change in circulating system pressure (4) Choke Line Pressure (measure by circulating at the Kill Rate through the choke manifold down the choke line and up the riser) (5) Corrected Choke Line Pressure = (6) Calculated Initial Circulating Pressure Measured Choke Line Pressure x Present Drilling Fluid Density Drilling Fluid Density When Choke Line Pressure Measured = Kill Rate Pressure plus Closed-in Drill Pipe Pressure = = Closed-in Drill Pipe Pressure 052 x Depth (TVD) = _ psi 052 x _ ft (9) Final Circulating Pressure = Kill Rate Pressure (10) Circulating Time To Bit = Drill Pipe Capacity x Drill String Length Kill Rate _ psi x _ lb/gal _ psi + _ lb/gal _ psi = _ = _ psi psi + Present Drilling Fluid Density + Trip Margin † + lb/gal + 0.3 lb/gal † = lb/gal x Required Drilling Fluid Density Original Drilling Fluid Density = = psi x bbl/ft x ft _ bpm _ lb/gal _ lb/gal = _ psi = _ (11) Strokes To Bit = Kill Rate x Time = _ stks/min x _ = stks _ Notes: *Considering pump efficiency † Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes Omit Trip Margin if only surface casing set or drilling fluid is near fracture gradient PREPARE DRILL PIPE PRESSURE SCHEDULE KILLING THE WELL Hold Drill Pipe Pressures shown for each drilling fluid density increment at times (or strokes) shown by adjusting choke, while holding Kill Rate constant If Drill Pipe Pressure increases, open the choke; if Drill Pipe Pressure decreases, close the choke When Required Drilling Fluid Density (8) reaches bit, hold Final Circulating Pressure (9) constant After gas reaches the choke line, sudden loss of hydrostatic pressure may result in rapid drop in Drill Pipe Pressure requiring quick choke adjustment At some time the choke may be wide open and Drill Pipe Pressure higher than scheduled Open kill line to choke for an additional choke line, if not already open If Drill Pipe Pressure cannot be reduced using wide open choke, hold Drill Pipe Pressure constant by reducing the pump rate After uncut drilling fluid of required density reaches the surface, shut down pump and check for flow If well is dead, circulate heavy drilling fluid into riser Take steps to circulate out possible gas trapped in blowout preventers using a closed diverter If possible, continue circulating slowly through choke line while displacing riser (over) = (7) If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole ESTABLISH CIRCULATION START INCREASING DRILLING FLUID DENSITY = lb/gal = 052 x ft x ( _ lb/gal – _ lb/gal) = psi Fill in bottom of graph with even increments of drilling fluid density from Initial to Required Drilling Fluid Density Plot Initial Circulating Pressure (6) above Initial Drilling Fluid Density Determine Final Circulating Pressure (9) and plot above Required Drilling Fluid Density (8) Draw a line between the points Read from graph Drill Pipe Pressure at each increment of drilling fluid density and record in blank spaces Record time (or strokes) at which suction pit has each increment of drilling fluid density Calculate Circulating Time (10) (or strokes) (11) to Bit Fill blank spaces with /2 Circulating Time (or strokes) to Bit Add /2 Circulating Time (or strokes) to Bit to time for each drilling fluid density increment VI x Leak-off Test Drilling Fluid Density (8) Required Drilling Fluid Density Record time or strokes at which fluid in suction pit is increased each 0.1 or 0.2 lb/gal on graph (7) Calculate Required Drilling Fluid Density (8) V _ psi 052 x _ ft + When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe casing pressure] Do not exceed Maximum Allowable Casing Pressure (2) Hang off drill pipe, check for trapped pressure, and record the following: Closed-in Drill Pipe Pressure psi, Casing Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl Open the kill line to a pressure gauge Slowly open the choke controlling the choke line and make adjustments as necessary to hold the kill line pressure constant while the pump is brought up to kill rate If kill line pressure monitoring cannot be done, allow the choke manifold pressure to drop by an amount equal to the corrected choke line pressure (5) Hold Kill Rate constant The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure (6) When approximately equal, use the choke to adjust the observed Drill Pipe Pressure to the calculated pressure If widely divergent, close in the well and consider alternatives Record time when circulation started hrs IV B Fracture Pressure Approved by: _ Contingency Procedure (2) if casing pressure reaches maximum approved: _ _ _ Normal Circulating Pressure and Rate: _ psi at stks/min and _ bpm* at _ lb/gal and _ ft Kill Pressure and Rate: Pump No , psi at stks/min and _ bpm* at _ lb/gal and _ ft (3) Pump No , psi at stks/min and _ bpm* at _ lb/gal and ft (3) Drill Pipe Capacity: _ bbl/ft, Choke Line Pressure at Kill Rate psi at bpm and lb/gal (4) Choke Line Pressure at Kill Rate psi at bpm and _ lb/gal (4) Choke Line Pressure at Kill Rate psi at bpm and _ lb/gal (4) II = Leak-off Pressure 052 x Casing Depth 87 API RECOMMENDED WELL CONTROL WORKSHEET Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) Displacement (bbl/stk.) Where: L D d Eff CONCURRENT METHOD (SUBSEA STACK) COMPANY WELL DATE DEPTH Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 PREPARED BY: _ COMPANY _ CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 (1) (2) (3) (4) (5) Upset Nominal (lb/ft) I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U 10.40 10.40 13.30 13.30 15.50 14.00 16.60 16.60 16.60 20.00 20.00 19.50 25.60 21.90 24.70 Approx (lb/ft) (2) 10.28 10.76 13.40 14.77 16.39 15.85 18.98 17.81 18.37 21.62 22.09 20.89 26.89 23.77 26.33 Capacity Tool Joint Name NC No Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H 26 31 31 38 38 46 50 46 50 46 50 50 (3) (3) Average Overall Joint O.D., Length, ft (4) in 3 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 Barrels Per Foot 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 Barrels Per 3-Joint Stand 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 Displacement Feet Per Barrel 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 Barrels Per 3-Joint Stand Barrels Per Foot (5) 0.00374 0.00392 0.00488 0.00501 0.00596 0.00577 0.00691 0.00648 0.00668 0.00786 0.00804 0.00760 0.00979 0.00865 0.00958 0.344 0.361 0.452 0.465 0.554 0.538 0.644 0.604 0.624 0.733 0.750 0.708 0.912 0.809 0.896 Barite Required = Drilling Fluid Volume x Sacks/100 bbl 100 Required Mixing Rate = Sacks/100 bbl x Kill Rate 100 = (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) = ( _ lb/gal – _ lb/gal) x _ bbl ( _ lb/gal – 8.34) = = = Stroke Length, in 7 7 7 7 8 8 sx/100 bbl _ bbl x _ sx/100 bbl 100 _ sx/100 bbl x bpm 100 = _ sx = _ sx/min DILUTION OF RESERVE DRILLING FLUID WITH WATER Barrels Water Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) 1470 x ( lb/gal – lb/gal) (35 – lb/gal) Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 (100 Percent Volumetric Efficiency) ****************** = Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in BARITE REQUIREMENTS = Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps Grade E drill pipe Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 Obsolete tool joint Based on an average pipe length of 29.4 feet before adding tool joints The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft3 and volume of one barrel equal to 5.61458 ft Sacks/100 bbl Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = _ bbl 88 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET DRILLERS METHOD DATE RIG (SUBSEA STACK) CALCULATIONS AND NOTES PROCEDURE I PRERECORDED INFORMATION Casing: Size in., Weight lb/ft, Grade , Internal Yield _ psi, Depth (TVD) ft Mechanical Pressure Limit psi Casing Pressure to Cause Fracture psi (1), based on present drilling fluid density of lb/gal Maximum Allowable Casing Pressure: Internal Closure psi Approved by: _ Entire Well Kill _ psi } III Leak-off Pressure 052 x Casing Depth + Leak-off Test Drilling Fluid Density _ psi B Fracture Pressure 052 x _ ft + lb/gal = lb/gal = 052 x Casing Depth + (Fracture Drilling Fluid Density – Present Drilling Fluid Density) = 052 x ft x ( _ lb/gal – _ lb/gal) = psi (2) If casing pressure reaches maximum allowed, follow the Contingency Procedure IMMEDIATE ACTION (3) Measure daily while drilling or after a significant change in circulating system pressure When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe casing pressure] Do not exceed Maximum Allowable Casing Pressure (2) Hang off drill pipe, check for trapped pressure and record the following: Closed-in Drill Pipe Pressure psi, Casing Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl (4) Choke Line Pressure (measure by circulating at the Kill Rate through the choke manifold down the choke line and up the riser.) ESTABLISH CIRCULATION (5) Corrected Choke Line Pressure Open the kill line to a pressure gauge Slowly open the choke controlling the choke line and make adjustments as necessary to hold the kill line pressure constant while the pump is brought up to kill rate If kill line pressure monitoring cannot be done, allow the choke manifold pressure to drop by an amount equal to the corrected choke line pressure (5) The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure (6) If not, investigate the cause Record the Drill Pipe Pressure psi at stks/min and bpm Record time when circulation started hrs IV = = (Name) Contingency Procedure (2) if casing pressure reaches maximum approved: Normal Circulating Pressure and Rate: _ psi at stks/min and _ bpm* at lb/gal and _ ft Kill Pressure and Rate:Pump No , _ _ psi at _ stks/min and _ bpm* at lb/gal and _ _ ft (3) Pump No , psi at stks/min and _ bpm* at _ lb/gal and _ ft (3) Drill Pipe Capacity: bbl/ft Choke Line Pressure at Kill Rate psi at bpm and lb/gal (4) II (1) A Fracture Drilling Fluid Density (6) Calculated Initial Circulating Pressure (7) Required Drilling Fluid Density CIRCULATE OUT THE KICK While holding Kill Rate constant, keep Drill Pipe Pressure constant by adjusting choke If Drill Pipe Pressure increases, open choke If Drill Pipe Pressure decreases, close choke Casing Pressure must be allowed to vary to maintain constant bottom-hole pressure When gas reaches the choke line, sudden loss of hydrostatic pressure may result in a rapid drop in Drill Pipe Pressure requiring quick choke adjustment When well is free of gas, salt water, and oil, stop pump and close choke Record New Closed-in Choke Manifold Pressure psi V INCREASE DRILLING FLUID DENSITY VI CIRCULATE HEAVY DRILLING FLUID = Measured Choke Line Pressure x Present Drilling Fluid Density Drilling Fluid Density When Choke Line Pressure Measured = Kill Rate Pressure plus Closed-in Drill Pipe Pressure = _ psi + _ psi = _ psi = Closed-in Drill Pipe Pressure 052 x Bit Depth (TVD) = psi 052 x _ ft + psi x _ _ lb/gal = lb/gal = _ psi + Present Drilling Fluid Density + Trip Margin † _ lb/gal + 0.3 lb/gal † = lb/gal (8) If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole Calculate the Required Drilling Fluid Density (7) and increase fluid density in the suction pit (8) Establish circulation as per item III, adding a 100 psi safety factor Let the New Closed-in Choke Manifold Pressure drop by the amount of the Corrected Choke Line Pressure (5) Hold Kill Rate constant and hold New Reduced Choke Manifold Pressure constant by varying the choke Maintain required drilling fluid density in pit while circulating Circulate heavy drilling fluid to bit using time (9) or strokes (10) When heavy drilling fluid reaches bit, read and record Final Drill Pipe Circulating Pressure psi Hold Final Drill Pipe Pressure constant by varying choke while holding Kill Rate constant At some time, the choke may be wide open and Drill Pipe Pressure higher than recorded Final Drill Pipe Circulating Pressure Open Kill Line to choke for an additional choke line, if not already open If Drill Pipe Pressure cannot be reduced using wide open choke, hold recorded Final Drill Pipe Pressure constant by reducing pump rate After uncut drilling fluid of required density reaches surface, shut down pump and check for flow If well is dead, circulate heavy drilling fluid into riser Take steps to circulate out possible gas trapped in blowout preventers using a closed diverter If possible, continue circulating slowly through choke line while displacing riser (over) (9) Circulating Time To Bit = Drill Pipe Capacity x Drill String Length Kill Rate (10) Strokes To Bit = Kill Rate x Time = _ stks/min x = = bbl/ft x _ ft bpm = _ stks _ Notes: *Considering pump efficiency † Trip Margin and Safety Factor may be omitted, but these give little risk of loss and circulation as the open hole and casing seat are subjected to higher pressures when circulating out the kick If Trip Margin is used, when heavy drilling fluid nears the surface the choke will be wide open and the Final Drill Pipe Circulation Pressure can no longer be controlled The Drill Pipe Pressure will slowly increase to compensate for the Trip Margin Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes 89 API RECOMMENDED WELL CONTROL WORKSHEET Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) DRILLERS METHOD (SUBSEA STACK) COMPANY WELL DATE DEPTH Displacement (bbl/stk.) Where: L D d Eff Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 PREPARED BY: COMPANY _ CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 (1) (2) (3) (4) (5) Tool Joint Upset Nominal (lb/ft) Approx (lb/ft) (2) I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U 10.40 10.40 13.30 13.30 15.50 14.00 16.60 16.60 16.60 20.00 20.00 19.50 25.60 21.90 24.70 10.28 10.76 13.40 14.77 16.39 15.85 18.98 17.81 18.37 21.62 22.09 20.89 26.89 23.77 26.33 Name NC No O.D., in Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H 26 31 31 38 38 46 50 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 46 50 46 50 50 (3) (3) Capacity Displacement Average Overall Joint Length, ft (4) Barrels Per Foot Barrels Per 3-Joint Stand Feet Per Barrel Barrels Per Foot (5) Barrels Per 3-Joint Stand 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 0.00374 0.00392 0.00488 0.00501 0.00596 0.00577 0.00691 0.00648 0.00668 0.00786 0.00804 0.00760 0.00979 0.00865 0.00958 0.344 0.361 0.452 0.465 0.554 0.538 0.644 0.604 0.624 0.733 0.750 0.708 0.912 0.809 0.896 Barite Required = Drilling Fluid Volume x Sacks/100 bbl 100 Required Mixing Rate = Sacks/100 bbl x Kill Rate 100 = = Stroke Length, in 7 7 7 7 8 8 = sx/100 bbl bbl x sx/100 bbl 100 _ sx/100 bbl x _ bpm 100 = _ sx = _ _ sx/min DILUTION OF RESERVE DRILLING FLUID WITH WATER Barrels Water = = (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) ( _ lb/gal – lb/gal) x _ bbl ( lb/gal – 8.34) Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) 1470 x ( lb/gal – _ lb/gal) (35 – lb/gal) Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 (100 Percent Volumetric Efficiency) ****************** = Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in BARITE REQUIREMENTS = Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps Grade E drill pipe Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 Obsolete tool joint Based on an average pipe length of 29.4 feet before adding tool joints The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft3 and volume of one barrel equal to 5.61458 ft Sacks/100 bbl Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = _ bbl 90 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 WELL NAME CONTRACTOR API RECOMMENDED WELL CONTROL WORKSHEET WAIT AND WEIGHT METHOD DATE RIG (SUBSEA STACK IN DEEP WATER) CALCULATIONS AND NOTES PROCEDURE I PRERECORDED INFORMATION (1) A Fracture Drilling Fluid Density Casing: Size in., Weight _ _ lb/ft, Grade _, Internal Yield _ _ psi, Depth (TVD) ft Mechanical Pressure Limit psi Static Choke Manifold Pressure To Cause Fracture _ psi (1), based on present drilling fluid density of _ lb/gal Maximum Allowable Choke Manifold Pressure: Initial Closure _ _ psi Approved by: _ Entire Well Kill _ psi } (Name) Contingency Procedure (2) if casing pressure reaches maximum approved: _ _ _ Normal Circulating Pressure and Rate: _ psi at _ stks/min and _ bpm* at _ lb/gal ft Kill Pressure (KP) and Rate (3) at lb/gal psi spm bpm* Depth, ft B Fracture Pressure = 052 x ft x ( lb/gal – _ lb/gal) = _ psi (2) If choke manifold pressure reaches maximum allowed, follow the Contingency Procedure (3) Measure daily while drilling or after a significant change in circulating system pressure (4) Determine by circulating through choke manifold, down choke and/or kill lines, and up riser (5) Required Drilling Fluid Density Choke Line Pressure Loss at Kill Rate (4) Choke Line Kill Line Choke and Kill P U M P No P U M P No Leak-off Pressure = + Leak-off Test Drilling Fluid Density 052 x Casing Depth psi = + _ lb/gal = _ lb/gal .052 x ft = 052 x Casing Depth x (Fracture Drilling Fluid Density – Present Drilling Fluid Density) = = Closed-in Drill Pipe Pressure + Present Drilling Fluid Density + Trip Margin † 052 x Bit Depth (TVD) _ psi + _ lb/gal + _ lb/gal .052 x ft (6) If two sections or two pits are weighted and reverse circulation established between, drilling fluid density is more evenly controlled while circulating the hole (7) If drill pipe pressure increases during weighting, reduce to initial stabilized value by bleeding through the choke (8) Initial Circulating Pressure (ICP) = Kill Rate Pressure plus Closed-in Drill Pipe Pressure = psi + _ psi = _ psi (9) Final Circulating Pressure (FCP) = Kill Rate Pressure x Drill Pipe Capacity: _ bbl/ft II IMMEDIATE ACTION When a kick occurs, stop rotary, raise kelly, stop pump [F open choke line and choke, close blowout preventer, close choke], or [F close blowout preventer, open choke line with choke closed, and observe choke manifold pressure] Do not allow choke manifold pressure to exceed maximum allowed (2) Hang off drill pipe, Check for trapped pressure, and record the following: Closed-in Drill Pipe Pressure psi, Closed-in Choke Manifold Pressure psi, Drilling Fluid Density lb/gal, Depth (TVD) ft, Kick Volume bbl (10) Circulating Time To Bit Required Drilling Fluid Density (MWR) Original Drilling Fluid Density (MWO) = _ psi x _ lb/gal = _ psi _ lb/gal _ bbl/ft x ft = _ = Drill Pipe Capacity x Drill String Length = Kill Rate _ bpm (11) Strokes To Bit = Kill Rate x Time = stks/min x = _ stks ((12) Initial Circulating Pressure (ICP) spm III INCREASE DRILLING FLUID DENSITY KP CIDPP (13) Final Circulating Pressure (FCP) ICP KP MWR/MWO FCP (14) Circulating Time To Bit P U M P No P U M P No Calculate the Required Drilling Fluid Density (5) and increase fluid density in the suction pit (6), (7) IV PREPARE DRILL PIPE PRESSURE SCHEDULE Determine Initial Circulating Pressures (8) and record in spaces provided (12) Determine Final Circulating Pressures (9) and record in space provided (13) Select a Kill Rate whose corresponding Choke Line Pressure is less than the Closed-in Choke Manifold Pressure Calculate Circulating Time to Bit (10) and Stokes to Bit (11) for the selected Kill Rate and record in the space provided (14) Plot Initial Circulating Pressure for the selected Kill Rate above zero time on the Drill Pipe Pressure schedule Plot Final Circulating Pressure for the selected Kill Rate above the corresponding Circulating Time to Bit Join the Initial and Final Circulating Pressures with a straight line Draw a line between the points Read Drill Pipe Pressure at five-minute intervals and record in space provided Select a second, lower Kill Rate and calculate the corresponding Final Circulating Pressure and record in space provided (13) Notes: *Considering pump efficiency † Trip Margins range from 0.0 to 0.3 lb/gal for hole sizes greater than 7-in diameter and from 0.0 to 0.5 lb/gal for smaller holes V ESTABLISH CIRCULATION Open the kill line to a pressure gauge Slowly open the choke controlling the choke line and make adjustments as necessary to hold the kill line pressure constant while the pump is brought up to the higher of the two preselected kill rates If kill line pressure monitoring cannot be done, allow the choke pressure to drop an amount equal to the corresponding choke line pressure loss (4) Hold Kill Rate constant The observed Drill Pipe Pressure should be equal to the Calculated Initial Circulating Pressure If not, investigate cause VI CIRCULATE HEAVY DRILLING FLUID Maintain Required Drilling Fluid Density in pits while circulating at Kill Rate Use choke to adjust Drill Pipe Pressure to values recorded at times or strokes shown If Drill Pipe Pressure increases, open the choke; if Drill Pipe Pressure decreases, close the choke When heavy drilling fluid reaches bit (10), (11), hold Final Circulating Pressure constant at Kill Rate When gas reaches the choke line, sudden loss of hydrostatic pressure may result in rapid drop in Drill Pipe Pressure requiring quick choke closure At some time, the choke may be wide open and Drill Pipe Pressure higher than scheduled The kill line can be used as an additional choke line, if desired, or the pumping rate can be reduced to the lower preselected rate and the Drill Pipe Pressure lowered to the corresponding Final Circulating Pressure using the choke After uncut drilling fluid of the required density reaches the surface, shut down the pump and check for flow If the well is dead, circulate the riser with drilling fluid of the required density before opening the blowout preventer (over) 91 stks API RECOMMENDED WELL CONTROL WORKSHEET Displacement of Duplex, Double-acting Pumps (90 Percent Volumetric Efficiency) Displacement (bbl/stk.) Where: L D d Eff WAIT AND WEIGHT METHOD (SUBSEA STACK IN DEEP WATER) COMPANY WELL DATE Stroke Length, in 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 DEPTH PREPARED BY: COMPANY CAPACITY AND DISPLACEMENT OF DRILL PIPE Drill Pipe (1) Weight O.D., in /8 /8 /2 /2 /2 4 /2 /2 /2 /2 /2 5 /2 /2 (1) (2) (3) (4) (5) Upset I.U E.U I.U E.U E.U E.U E.U I.E.U I.E.U E.U I.E.U I.E.U I.E.U I.E.U I.E.U Nominal Approx (lb/ft) (lb/ft) (2) 10.40 10.28 10.40 10.76 13.30 13.40 13.30 14.77 15.50 16.39 14.00 15.85 16.60 18.98 16.60 17.81 16.60 18.37 20.00 21.62 20.00 22.09 19.50 20.89 25.60 26.89 21.90 23.77 24.70 26.33 Average Overall Joint Length, ft (4) 30.64 30.74 30.86 30.94 30.99 31.10 31.07 31.06 31.11 31.07 31.11 31.05 31.05 31.17 31.17 Tool Joint Name Slim Hole I.F Slim Hole I.F I.F I.F I.F H-90 X.H I.F X.H X.H X.H F.H F.H NC No 26 31 31 38 38 46 50 46 50 46 50 50 (3) (3) O.D., in 3 /8 /8 /8 /4 6 /8 6 /4 /8 /4 /8 /8 7 Capacity Barrels Per 3-Joint Stand 0.404 0.414 0.669 0.686 0.611 1.008 1.323 1.292 1.301 1.200 1.173 1.626 1.423 2.028 1.942 Barrels Per Foot 0.00440 0.00449 0.00723 0.00739 0.00657 0.01081 0.01419 0.01394 0.01394 0.01287 0.01257 0.01746 0.01528 0.02169 0.02077 Feet Per Barrel 227.5 222.7 138.4 135.4 152.3 92.6 70.5 71.7 71.8 77.3 79.5 57.3 65.5 46.1 48.2 Displacement Barrels Barrels Per Per 3-Joint Foot (5) Stand 0.00374 0.344 0.00392 0.361 0.00488 0.452 0.00501 0.465 0.00596 0.554 0.00577 0.538 0.00691 0.644 0.00648 0.604 0.00668 0.624 0.00786 0.733 0.00804 0.750 0.00760 0.708 0.00979 0.912 0.00865 0.809 0.00958 0.896 = Barite Required = Drilling Fluid Volume x Sacks/100 bbl 100 = Stroke Length, in 7 7 7 7 8 8 Required Mixing Rate = Sacks/100 bbl x Kill Rate 100 = sx/100 bbl _ bbl x _ 100 sx/100 bbl _ sx/100 bbl x _ bpm 100 = sx = sx/min DILUTION OF RESERVE DRILLING FLUID WITH WATER Barrels Water = = (Present Drilling Fluid Density – Desired Drilling Fluid Density) x Present Drilling Fluid Volume (Desired Drilling Fluid Density – 8.34) ( _ lb/gal – lb/gal) x bbl ( _ lb/gal – 8.34) Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 6 /2 7 /2 Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 Displacement, bbl/stk .115 142 172 205 241 279 319 165 198 233 271 312 157 190 225 263 304 1470 x (Required Drilling Fluid Density – Present Drilling Fluid Density) (35 – Required Drilling Fluid Density) 1470 x ( lb/gal – _ lb/gal) (35 – lb/gal) Stroke Length, in 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 (100 Percent Volumetric Efficiency) ****************** = Displacement, bbl/stk .102 126 153 182 214 248 284 147 176 207 241 277 316 139 168 200 234 270 Displacement (bbl/stk.) = 000243 x L x D Where: L = Stroke length, in D = Liner diameter, in BARITE REQUIREMENTS = Rod Diameter, in /2 /2 /2 /2 /2 /2 /2 3 3 3 /2 /2 /2 /2 /2 0001619 L [2D – d ] (Eff.) Stroke length, in Liner diameter, in Rod diameter, in Volumetric efficiency, decimal fraction Displacement of Triplex, Single-acting Pumps Grade E drill pipe Table 2.10, API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits, Twelfth Edition, May 1987 Obsolete tool joint Based on an average pipe length of 29.4 feet before adding tool joints The approximate weight per foot is converted to barrels using steel density of 489.54 lb/ft3 and volume of one barrel equal to 5.61458 ft Sacks/100 bbl Liner Diameter, in 5 /2 6 /2 7 /2 6 /2 7 /2 8 /2 6 /2 7 /2 = = = = = = bbl 92 Liner Size, in 3 /2 4 /2 5 /2 6 /2 /2 5 /2 6 /2 Displacement, bbl/stk .0153 0208 0272 0344 0425 0514 0612 0718 0833 0393 0486 0588 0699 0821 Stroke Length, in 9 9 9 10 10 10 10 10 12 12 12 12 12 Liner Size, in /2 4 /2 5 /2 /2 5 /2 6 /2 5 /2 6 /2 Displacement, bbl/stk .0268 0350 0443 0546 0661 0787 0492 0607 0735 0874 1026 0729 0882 1049 1231 1428 Effective January 1, 2006 API Members receive a 30% discount where applicable The member discount does not apply to purchases made for the purpose of resale or for incorporation into commercial products, training courses, workshops, or other commercial enterprises 2006 Publications Order Form Available through Global Engineering Documents: Date: ❏ API Member (Check if Yes) Invoice To (❏ Check here if same as “Ship To”) Ship To (UPS will not deliver to a P.O Box) Name: Name: Title: Title: Company: Company: Department: Department: Address: Address: Phone Orders: 1-800-854-7179 (Toll-free in the U.S and Canada) 303-397-7956 (Local and International) 303-397-2740 www.global.ihs.com Fax Orders: Online Orders: City: State/Province: City: State/Province: Zip/Postal Code: Country: Zip/Postal Code: Country: Telephone: Telephone: Fax: Fax: E-Mail: E-Mail: Quantity Product Number Title GX16A03 G07242 Spec 16A/ISO 13533, Drill-through Equipment, Petroleum and natural gas industries Drilling and production equipment: Drill through equipment (Modified) G16D02 G64002 Spec 16D, Control Systems for Drilling Well Control Equipment G53003 RP 53, Blowout Prevention Equipment Systems for Drilling Operations ❏ Payment Enclosed Spec 16C, Choke and Kill Systems RP 64, Diverter Systems Equipment and Operations ❏ P.O No (Enclose Copy) ❏ MasterCard ❏ American Express Expiration Date: Signature: Total $137.00 $110.00 $147.00 $86.00 $110.00 Subtotal ❏ Diners Club ❏ Discover Rush Shipping Fee (see below) Shipping and Handling (see below) Credit Card No.: Print Name (As It Appears on Card): Unit Price Applicable Sales Tax (see below) ❏ Charge My Global Account No ❏ VISA SO★ Total (in U.S Dollars) ★ To be placed on Standing Order for future editions of this publication, place a check mark in the SO column and sign here: Pricing and availability subject to change without notice Mail Orders – Payment by check or money order in U.S dollars is required except for established accounts State and local taxes, $10 processing fee*, and 5% shipping must be added Send mail orders to: API Publications, Global Engineering Documents, 15 Inverness Way East, M/S C303B, Englewood, CO 80112-5776, USA Purchase Orders – Purchase orders are accepted from established accounts Invoice will include actual freight cost, a $10 processing fee*, plus state and local taxes Telephone Orders – If ordering by telephone, a $10 processing fee* and actual freight costs will be added to the order Sales Tax – All U.S purchases must include applicable state and local sales tax Customers claiming tax-exempt status must provide Global with a copy of their exemption certificate Shipping (U.S Orders) – Orders shipped within the U.S are sent via traceable means Most orders are shipped the same day Subscription updates are sent by First-Class Mail Other options, including next-day service, air service, and fax transmission are available at additional cost Call 1-800-854-7179 for more information Shipping (International Orders) – Standard international shipping is by air express courier service Subscription updates are sent by World Mail Normal delivery is 3-4 days from shipping date Rush Shipping Fee – Next Day Delivery orders charge is $20 in addition to the carrier charges Next Day Delivery orders must be placed by 2:00 p.m MST to ensure overnight delivery Returns – All returns must be pre-approved by calling Global’s Customer Service Department at 1-800-624-3974 for information and assistance There may be a 15% restocking fee Special order items, electronic documents, and age-dated materials are non-returnable *Minimum Order – There is a $50 minimum for all orders containing hardcopy documents The $50 minimum applies to the order subtotal including the $10 processing fee, excluding any applicable taxes and freight charges If the total cost of the documents on the order plus the $10 processing fee is less than $50, the processing fee will be increased to bring the order amount up to the $50 minimum This processing fee will be applied before any applicable deposit account, quantity or member discounts have been applied There is no minimum for orders containing only electronically delivered documents