Well Control for Completions and Interventions

Description

Well Control for Completions and Interventions explores the standards that ensure safe and efficient production flow, well integrity and well control for oil rigs, focusing on the post-Macondo environment where tighter regulations and new standards are in place worldwide. Too many training facilities currently focus only on the drilling side of the well’s cycle when teaching well control, hence the need for this informative guide on the topic. This long-awaited manual for engineers and managers involved in the well completion and intervention side of a well’s life covers the fundamentals of design, equipment and completion fluids. In addition, the book covers more important and distinguishing components, such as well barriers and integrity envelopes, well kill methods specific to well completion, and other forms of operations that involve completion, like pumping and stimulation (including hydraulic fracturing and shale), coiled tubing, wireline, and subsea intervention. Copyright Copyright Acknowledgments One Introduction and Well Control Fundamentals 1.1 Introduction 1.1.1 Workover or intervention? 1.1.1.1 Pressure control and well control 1.1.2 Why interventions and workovers are performed 1.1.2.1 Production decline 1.1.2.1.1 Scale precipitation 1.1.2.1.2 Wax deposits 1.1.2.1.3 Asphaltines 1.1.2.1.4 Water and gas production 1.1.2.2 Well stimulation 1.1.2.2.1 Hydraulic fracturing (Fracking) 1.1.2.2.2 Acid fracturing and acid matrix treatments 1.1.2.3 Artificial lift 1.1.2.4 Mechanical repairs 1.1.3 The geology of hydrocarbon reservoirs 1.1.3.1 Sedimentary rock 1.1.3.2 Hydrocarbon traps 1.1.3.3 Porosity and permeability 1.1.4 Formation pressure and reservoir pressure 1.1.4.1 Under-compaction in massive shale beds 1.1.4.2 Salt beds 1.1.4.3 Salt domes or diapirs 1.1.4.4 Tectonic forces 1.1.4.5 Faulting 1.1.4.6 Cross-flow 1.1.5 Formation fracture pressure 1.1.5.1 Formation leak-off tests 1.1.5.2 Formation integrity tests 1.1.5.3 Unit systems 1.1.6 Hydrostatic pressure calculations 1.1.6.1 Hydrostatic pressure 1.1.6.1.1 Metric (bar/m) 1.1.6.1.2 Crude oil density 1.1.6.1.3 True vertical depth and measured depth 1.1.6.2 Calculating bottom-hole pressure 1.1.6.2.1 Surface pressure 1.1.6.3 Gas hydrostatic pressure 1.1.7 Underbalance and overbalance pressure 1.1.8 Tubing and casing volume and capacity 1.1.8.1 Using tables When calculating capacity remember to use the measured depth of the well Example volume calculation 1.1.9 Gas hydrates 1.1.9.1 Hydrate risk during well interventions 1.1.9.2 Hydrate prevention 1.1.9.3 Hydrate removal 1.1.9.3.1 Chemical disassociation 1.1.9.3.2 Pressure reduction 1.1.9.3.3 Elevate the temperature 1.1.10 Hydrogen sulfide (H2S) 1.1.10.1 Hydrogen sulfide safety precautions 1.1.10.2 Hydrogen sulfide and equipment corrosion 1.1.10.3 Carbon dioxide (sweet) corrosion 1.1.11 Roles and responsibilities 1.1.11.1 Person in charge of well control 1.1.11.1.1 Responsibilities during rig supported completion and workover operations 1.1.11.1.2 Responding to a well control incident 1.1.11.2 Responsibilities during Interventions on live wells (independent of rig support) 1.1.11.2.1 Prejob checks 1.1.11.2.2 During a well control incident 1.1.12 Human and organizational factors 1.1.12.1 Situation awareness 1.1.12.2 Decision-making 1.1.12.3 Communication 1.1.12.4 Teamwork 1.1.12.5 Leadership 1.1.12.6 Factors that impact human performance 1.1.13 Well control certificates 1.1.13.1 IWCF well control training 1.1.13.2 Drilling well control 1.1.13.3 Well intervention well control 1.1.13.4 IADC well control References Two Well Construction and Completion Design 2.1 Well Construction 2.2 Types of Completion 2.2.1 The reservoir completion (sand-face or lower completion) 2.2.2 Open hole (barefoot) completions 2.2.3 Open hole completions with predrilled and slotted liner 2.2.4 Cased and perforated completion 2.2.5 Sand control completions 2.2.6 The upper completion 2.2.7 No tubing: Flow through production casing 2.2.8 Tubing only completion: no production packer 2.2.9 Single production tubing string with production packer (reverse taper configuration) 2.2.10 Single production tubing string with production packer (mono-bore configuration) 2.2.11 Single string production tubing completed across multiple reservoir zones 2.2.12 Multilateral Wells 2.3 Summary References Three Completion Equipment 3.1 The Wellhead, Tubing Hanger, and Christmas Tree 3.1.1 The wellhead 3.1.2 Tubing hangers 3.1.3 Wellhead and Christmas tree service tools 3.1.4 The Christmas Tree 3.1.4.1 Conventional (vertical) Christmas trees 3.1.4.2 The horizontal or spool tree 3.2 Tubulars 3.2.1 Tubing size 3.2.2 Tubing weight 3.2.3 Tubing grade and tubing yield 3.2.4 Tubing length range 3.3 Tubular Connections 3.3.1 American Petroleum Institute connections 3.3.2 Premium connections 3.4 Production Liners 3.4.1 The liner hanger 3.4.2 Liner top packers 3.4.3 External casing packers 3.4.4 Swell packers 3.5 Wireline Entry Guides 3.6 Liner Top Seal Assembly 3.7 Fluid Loss Control Valves 3.8 Landing Nipple 3.9 Flow Couplings and Blast Joints 3.9.1 Flow coupling 3.9.2 Blast joint 3.10 Production Packers 3.10.1 Permanent packers 3.10.2 Retrievable packers 3.10.3 Permanent retrievable packers 3.10.4 Multistring packers 3.11 Packer Setting 3.12 Packer-to-Tubing Connection 3.12.1 Premium threads 3.12.2 Ratch latch or anchor latch 3.12.3 Locator seal assembly 3.12.4 Seal bore extension 3.12.5 J-Latch connector 3.12.6 Seal assembly and polished bore receptacle (ELTSR)d 3.12.7 Telescoping joint 3.13 Chemical Injection Mandrels 3.14 Downhole Pressure and Temperature Gauges 3.15 Sliding Sleeves 3.16 Ported Nipples 3.17 Inflow Valves (Intelligent Completions) 3.18 Side Pocket Mandrels 3.19 Subsurface Safety Valves 3.19.1 Subsurface controlled valves 3.19.1.1 Pressure differential safety valves 3.19.1.2 Ambient pressure operated valves 3.19.1.3 Injection valves 3.19.2 Surface controlled valves 3.19.3 Equalizing or nonequalizing valve? 3.19.4 Tubing retrievable or wireline retrievable valves? 3.19.5 Installation of surface controlled downhole safety valves 3.19.6 Annulus safety valves 3.20 Lubricator Valves 3.21 Control Lines 3.22 Control Line Clamps References Four Well Control Surface Equipment 4.1 Introduction 4.2 The Blow Out Preventer Stack 4.2.1 Blow out preventer classification 4.3 Routine Testing of Blow Out Prevention Equipment 4.3.1 Function test 4.3.2 Pressure tests 4.3.3 Crew drill 4.4 Kill and Choke Lines and the Choke Manifold 4.5 Chokes 4.5.1 Positive (fixed diameter) chokes 4.5.2 Manually adjustable choke 4.5.3 Remotely operated choke 4.5.4 Choke operation 4.6 Gate Valves 4.6.1 Split gate valves 4.6.2 Slab (floating) gate 4.6.3 Rising and non-rising stem valves 4.6.4 High closing ratio valves 4.6.5 Check valve or non-return valve 4.7 Annular Preventers 4.7.1 Cameron (Sclumberger) D and DL annular preventers 4.7.2 Hydril GK preventer 4.7.3 Hydril GL preventer 4.7.4 Hydril GX annular preventer 4.7.4.1 The Shaffer’s (NOV) spherical annular preventer 4.7.5 Care and use of annular preventers 4.7.6 Stripping with annular preventers 4.8 Ram Preventers 4.8.1 Pipe rams 4.8.2 Variable bore rams 4.8.3 Blind rams/shearing blind rams 4.9 Blow Out Preventer Control System 4.9.1 Operating principles and main components 4.9.2 Accumulator bottles 4.9.3 Accumulator system pumps 4.9.4 The manifold system 4.9.5 Fluid reservoir 4.9.6 Remote blow out preventer control panel 4.9.7 Accumulator volume calculations 4.10 In Pipe Shut-Off Devices 4.10.1 Kelly valves 4.10.2 Top drive valves 4.10.3 Full opening safety valve (FOSV) 4.10.4 Inside blow out preventer (gray valve) 4.10.5 Drill-string float valve 4.11 Mud Gas Separator 4.12 Fluid Storage 4.12.1 Fluid pumps 4.13 Flanges, Ring Gaskets, and Seals (API 6A) 4.13.1 Flanges 4.13.2 Ring gaskets 4.13.2.1 “R” ring gasket 4.13.2.2 “RX” pressure energized ring gasket 4.13.2.3 “BX” pressure energized ring gasket References Five Completion, Workover, and Intervention Fluids 5.1 Introduction 5.2 Brine Selection 5.3 Brine Density 5.3.1 Adjusting brine density for wellbore temperature and pressure 5.4 Crystallization Temperature 5.4.1 Determining crystallization temperature 5.4.2 Pressure effect on crystallization temperature 5.5 Safety and the Environment 5.6 Brine Compatibility 5.6.1 Fluid compatibility with completion materials (metals) 5.6.2 Fluid compatibility with completion materials (elastomers) 5.6.3 Brine compatibility with the formation 5.6.4 Brine additives 5.7 Brine Clarity and Solids Content 5.8 Brine Filtration 5.9 Fluid Loss Control 5.9.1 Solids-free lost circulation material 5.9.2 Example fluid loss calculations 5.9.3 Bridging solids 5.9.3.1 Calcium carbonate 5.9.3.2 Sized salt 5.9.3.3 Cellulose fibers 5.9.3.4 Oil soluble resin 5.9.4 Mechanical fluid loss control 5.10 How Much Brine Is Needed? 5.10.1 Wellbore capacity 5.10.2 Surface piping 5.10.3 Holding tanks 5.10.4 Filtration capacity 5.10.5 Contingency 5.10.6 Brine volume summary 5.11 Alternatives to Brine References Six Well Barriers 6.1 Defining Well Barriers and Well Barrier Elements 6.2 Barrier Classification 6.2.1 Mechanical barriers 6.2.2 Fluid barriers 6.3 Barrier Testing 6.4 Inflow Testing 6.5 Nonconformance With Barrier Policy 6.6 Barrier Requirements in Subhydrostatic Reservoirs 6.7 Well Intervention Well Control Barriers 6.7.1 Wireline 6.7.2 Coiled tubing 6.7.2.1 External pressure control 6.7.2.2 Internal pressure control 6.8 Hydraulic Workover (Snubbing) Unit: Live Well Operations 6.8.1 External pressure control 6.8.2 Internal pressure control 6.9 Well Barrier Schematics 6.9.1 Tripping with open ended completion tubing or work string – open perforations 6.9.2 Removing BOP and installing Christmas tree 6.9.3 Gas lifted production well with annular safety valve (ASV) 6.9.4 Barriers during wireline intervention in a live well 6.9.5 Barriers during wireline intervention in a live well 6.9.6 Hydraulic workover unit: running tubing in to a live well (shear rams able to function) 6.9.7 Subsea well test string—well shut in after flowing References Seven Well Kill, Kick Detection, and Well Shut-In 7.1 Introduction 7.2 Workover and Intervention Well Kill Planning 7.2.1 Essential information 7.2.2 Wellbore preparation 7.3 Well Kill: Reverse Circulation 7.3.1 Static and circulating pressure 7.3.2 Equivalent circulating density 7.3.3 Slow circulation rate 7.3.4 U tube pressure 7.3.5 Opening the circulation path 7.3.6 Plugging the well 7.3.7 Pumping the kill fluid 7.3.8 Reverse circulation: worked example 1. Plugged vertical well 7.3.8.1 Calculate the gradient of kill weight fluid required to overbalance well pressure by 200psi 7.3.8.2 Tubing and annulus volumes 7.3.8.3 Calculate pressures before and after opening the sliding side door 7.3.8.4 Begin kill 7.3.8.5 Tubing filled with annulus (packer) fluid 7.3.8.6 Annulus filled with kill fluid 7.3.8.7 Tubing displaced to kill fluid 7.3.9 Reverse circulation: worked example 2—plugged vertical well with heavy fluid in the annulus 7.3.9.1 Calculate tubing and casing pressure before and after opening the sliding side door 7.3.9.2 Calculate the fluid level (H) in the annulus if the tubing head pressure is bled to 0psi 7.3.9.3 Pumping the kill weight fluid 7.3.9.4 Kill fluid at the sliding side door 7.3.9.5 Displace tubing to kill weight fluid 7.3.10 Example 3 reverse circulation: deviated well with tapered string 7.3.10.1 Obtaining measured versus vertical depth data 7.3.10.2 Calculate reservoir pressure 7.3.10.3 Calculate kill weight fluid needed to give 200psi overbalance at the sliding side door 7.3.10.4 Calculate pressure differential at the sliding side door before and after opening 7.3.10.5 Calculate tubing and annulus capacities 7.4 Non-Circulating Kill: Bullhead 7.4.1 Before a bullhead kill 7.4.2 Bullhead calculations: preparing the kill sheet 1 Calculate the kill fluid density 2 Calculate the volume of fluid required to kill the well (fluid pump to reservoir) 3 Calculate the maximum surface pump pressure (formation fracture limit) at the start of the kill 4 Calculate the maximum surface pump pressure (formation fracture limit) at the end of the kill 5 Tubing burst limit 6 Calculate maximum pump pressure (tubing burst mechanical limit) at the start of the kill 7 Calculate maximum pump pressure (tubing burst mechanical limit) at the end of the kill 7.4.3 Bullhead procedure 7.4.4 Bullhead kill sheet example: vertical well 7.5 Gas Laws and Gas Behavior 7.5.1 Gas migration in a closed-in system 7.6 Procedure for Controlling Gas Migration 7.6.1 Constant tubing pressure 7.6.1.1 Procedure for constant tubing pressure bleed method 7.6.2 Volumetric method 7.7 Lubricate-and-Bleed 7.7.1 The constant volume method (lubricate and bleed) 7.7.1.1 Constant volume method. Calculations and procedure 7.7.1.2 Example lubricate and bleed kill using the constant volume method 7.7.2 Lubricate and bleed. Constant volume method (no plug) 7.7.2.1 Example calculation 7.7.3 Lubricate and bleed. Constant pressure method 7.7.3.1 Procedure for the constant pressure method (lubricate and bleed) 7.7.3.2 Example “pressure method” lubricate and bleed well kill 7.7.4 Alternative (simplified) pressure method 7.7.4.1 Alternative pressure method (example) 7.8 Causes and Detection of Kicks 7.8.1 Fluid loss to the formation 7.8.2 Loss of hydrostatic overbalance 7.8.3 Fluid level changes caused by pipe displacement 7.8.4 Swabbing and surging 7.8.5 Mechanical failure 7.8.6 Disabled alarms 7.9 Kick Detection 7.9.1 Positive kick indication 7.10 Minimizing the Influx 7.10.1 Establishing reservoir pressure, influx size, and influx type 7.11 Shut-In Procedures 7.11.1 Close-in procedure whilst circulating 7.11.2 Shut-in procedure whilst tripping pipe 7.12 Regaining Well Control Following a Kick 7.12.1 The drillers method 7.12.1.1 Outline procedure 7.12.1.1.1 First circulation 7.12.1.1.2 Second circulation (if required) 7.12.2 Forward circulation: wait and weight 7.12.2.1 Outline procedure 7.12.3 Bullhead and lubricate-and-bleed 7.12.4 High angle and horizontal wells 7.12.5 Multi-lateral wells 7.13 Completion and Workover: Well Control Contingencies 7.13.1 Running the liner 7.13.2 Running slotted liners and sand control screens 7.13.3 Pre-completion wireline perforating 7.13.4 Tubing conveyed perforation guns in an overbalanced well 7.13.5 Underbalanced perforation; tubing conveyed perforation guns run on a drill stem test (DST) 7.13.6 Wellbore clean-out 7.13.7 Fluid loss control valves 7.13.8 Running electric submersible pumps 7.13.9 Running production tubing 7.13.10 Running dual string completions 7.13.11 Completion components 7.13.12 Daylight only operations 7.13.12.1 Procedure for opening the well in the morning 7.13.12.2 Other considerations for daylight only operations 7.13.13 Failure to meet barrier policy 7.13.14 Pulling damaged and corroded tubing 7.13.15 Remedial operations 7.13.16 Workover in steam flood fields 7.13.17 Unconventional (shale) reservoirs References Eight Pumping and Stimulation 8.1 Pumping Equipment 8.1.1 Centrifugal pumps 8.1.2 Reciprocating pumps 8.1.3 Guidelines for the use of mud pumps and cement pumps 8.1.3.1 Mud pumps 8.1.3.2 Cement pump 8.2 Temporary High Pressure Lines 8.2.1 Temporary high pressure lines: connections 8.2.1.1 Connection mismatch 8.2.2 Valves for temporary flowlines 8.2.3 Nonreturn valves 8.2.4 Pressure relief valves 8.2.5 Wellhead or tree connection 8.2.6 Securing high pressure temporary flowlines 8.3 Pumping Operations 8.3.1 Acid wash (carbonate scale removal) 8.3.2 Chemical inhibitor squeeze treatment 8.3.3 Cement squeeze 8.3.4 Hydraulic propped fracture treatment 8.3.5 Acid stimulation of carbonate reservoirs 8.4 Well Control Considerations During Pumping and Stimulation Operations 8.4.1 Special considerations when using frac boats 8.4.2 Formation fracture pressure 8.4.3 Surface controlled subsurface safety valve 8.4.4 Gas lift wells 8.4.5 Tree saver valves 8.4.6 Tubing loads during pumping operations 8.4.6.1 Thermal effects 8.4.6.2 Piston forces 8.4.6.3 Ballooning 8.5 Operation Specific Well Integrity and Well Control Concerns 8.5.1 Acid wash 8.5.2 Chemical inhibitor squeeze 8.5.3 Hydraulic propped fracture treatment 8.5.4 Acid stimulation in carbonate reservoirs 8.6 The Price of Getting It Wrong References Nine Wireline Operations 9.1 Wireline Interventions in Live Wells 9.2 The Wire 9.2.1 Slickline 9.2.2 Braided cable (non-conductive) 9.2.3 Electric line (e-line) 9.2.4 Care and handling of wireline 9.2.5 Spooling wire 9.2.6 Ductility testing 9.3 Wireline Surface Equipment 9.3.1 The wireline winch 9.3.1.1 Winch controls 9.3.1.2 The weight indicator 9.3.1.3 Depth measurement 9.3.1.4 The power pack 9.3.2 Wireline pressure control equipment 9.3.2.1 Equipment configuration 9.3.2.2 Slickline stuffing box 9.3.2.3 Liquid seal stuffing box 9.3.2.4 Grease injection head 9.3.2.5 Grease injection pump 9.3.2.6 Wireline blow out preventer (wireline valve) 9.3.2.7 Wireline blow out preventer: ram configuration 9.3.2.8 Shear seal wireline valve (blow out preventer) 9.3.2.9 Wireline lubricator 9.3.2.10 Quick union connections 9.3.3 Pressure control equipment: accessories 9.3.3.1 Pump-in tee 9.3.3.2 Chemical injection sub 9.3.3.3 Tool catcher (tool trap) 9.3.3.4 Lubricator test sub: quick test sub 9.3.3.5 Side entry sub (Y spool) 9.3.3.6 Cable cutting sub 9.3.4 Single well control panels 9.3.5 Well control barriers during wireline operations 9.3.6 Rigging up on wells equipped with a conventional (vertical) Christmas tree 9.3.7 Rigging up on wells equipped with horizontal (spool) trees 9.3.8 Drilling blow out preventer still in place: production tubing or landing string in the rotary table 9.3.9 Drilling blow out preventer in place: no tubing in the well 9.3.10 Pressure control: sub-surface lubricator valve 9.4 Wireline Downhole Equipment 9.4.1 Basic slickline toolstring 9.4.2 Toolstring configuration 9.5 Well Control During Wireline Interventions 9.5.1 Pre-intervention preparations 9.5.2 Rigging up: equipment location and layout 9.5.3 Pressure testing surface equipment: preparation 9.5.4 Pressure testing surface equipment 9.5.5 Testing the blow out preventer (wireline valve) 9.5.5.1 Testing the shear seal blow out preventer 9.5.6 Slickline blow out preventer test 9.5.7 Braided cable (e-line) blow out preventer test 9.5.8 Pressure control equipment: full body test 9.5.9 Pressure control equipment: bleed down after wireline intervention 9.6 Well Control During Live Well Wireline Interventions 9.6.1 Leaking Stuffing Box (Slickline) 9.6.2 Leaking Grease Head (Braided Cable and E-Line) 9.6.3 Braided Cable and E-Line. Broken Wire Strand (Bird’s Nest) 9.6.4 Leaking pressure control equipment: above the blow out preventer 9.6.5 Leaking Pressure Control Equipment: Leak Below the Blow Out Preventer 9.6.6 Pressure Control During Wireline Fishing Operations 9.6.7 Dealing with a stuck toolstring 9.6.8 Pulling the weak point (e-line operations) 9.6.9 Dropping a cutter bar: well control considerations 9.6.10 Using a lubricator “Y” sub (slickline) 9.6.11 Wire parts at the surface 9.6.12 Failure of wireline winch power pack or mechanical failure of the winch References Ten Coiled Tubing Well Control 10.1 Introduction 10.2 Coiled Tubing Equipment 10.2.1 Coiled tubing: the pipe 10.2.1.1 Pipe performance 10.2.1.2 Corrosion resistance 10.3 Well Control Equipment 10.3.1 The stripper or pack-off 10.3.2 Coiled tubing blow out preventers 10.3.2.1 Blind ram assembly 10.3.2.2 Shear rams 10.3.2.3 Slip rams 10.3.2.4 Pipe rams 10.3.2.5 Coiled tubing blow out preventer operating sequence 10.3.2.6 Changing the ram configuration in quad blow out preventers 10.3.3 Combination blow out preventers 10.3.4 Shear seal blow out preventer 10.3.5 Blow out preventer operations: opening and closing the rams 10.3.5.1 Closing and locking and opening the rams 10.3.6 Coiled tubing barriers 10.3.6.1 Well pressure retaining barriers (barriers external to the coiled tubing) 10.3.6.2 Coiled tubing reel: internal pressure control 10.4 The Injector Head 10.4.1 Guide arch (gooseneck) 10.4.2 Weight indicator 10.4.3 Depth measurement equipment 10.4.4 The reel 10.4.5 The power pack 10.4.6 Control cabin 10.4.7 Rigging up coiled tubing on floating rigs and platforms 10.4.8 Calculating stripping and snubbing forces 10.5 Downhole Tools and the Coiled Tubing Bottom Hole Assembly 10.5.1 Coiled tubing connectors 10.5.2 Check valves 10.5.3 Back pressure valve 10.5.4 Disconnect sub 10.5.5 Circulating sub 10.5.6 Straight bar 10.6 Coiled Tubing Operations 10.6.1 Nitrogen gas lift 10.6.2 Wellbore clean out operations 10.6.3 Reverse circulation wellbore clean out 10.6.3.1 Reverse circulation clean out: an overview 10.6.3.2 Reverse circulation clean out: candidate wells 10.6.3.3 Bottom hole assembly selection 10.6.3.4 Collapse prevention 10.6.3.5 Operational guidelines 10.6.4 Acid treatments 10.6.5 Removal of hard scale 10.6.6 Mechanical interventions with coiled tubing 10.6.7 Running perforating guns on coiled tubing 10.7 General Coiled Tubing Operating Guidelines 10.7.1 Prejob checks 10.7.2 Prejob testing of pressure control equipment 10.7.2.1 Testing shear/seal blow out preventers 10.7.2.2 Testing the blind rams, shear rams, and riser 10.7.2.3 Coiled tubing reel 10.7.2.4 Stripper 10.7.2.5 Pipe rams 10.7.2.6 Bottom hole assembly internal check valves 10.7.3 Running coil in the well 10.7.3.1 Recommended running speeds 10.7.3.2 Pull tests 10.8 Well Control and Emergency Procedures 10.8.1 Power pack failure 10.8.2 Coiled tubing runaway 10.8.2.1 Pipe heavy coiled tubing runaway 10.8.2.2 Pipe-light coiled tubing runaway 10.8.3 Failure of reel hydraulic motor 10.8.4 Injector replacement 10.8.5 Hoist failure with pipe in the hole 10.8.6 Leaking coil tubing at surface (above the stripper) 10.8.7 Leak in the coiled tubing below the stripper 10.8.8 Riser leak 10.8.9 Leaking stripper rubber 10.8.10 Collapsed pipe 10.8.11 Tubing kinked 10.8.11.1 Tubing kinked below the stuffing box 10.8.11.2 Tubing kinked above the stuffing box and below the injector chain 10.8.12 Tubing parts at the surface 10.8.13 Stuck pipe 10.8.14 Tubing parted downhole 10.8.15 Tubing pulls out of stripper 10.8.16 Unable to circulate 10.8.17 Offshore platform operations 10.8.17.1 Production shut-down 10.8.17.2 Muster alarm 10.8.17.3 Platform abandonment References Eleven Hydraulic Workover (Snubbing) Operation 11.1 Introduction 11.2 Hydraulic Workover Operations 11.3 Hydraulic Workover Units: The Advantages 11.4 Rig Up Configuration: An Overview 11.5 Hydraulic Workover Unit 11.5.1 The hydraulic jack 11.5.2 Slip window 11.5.3 Traveling slips and stationary slips 11.5.4 The telescoping guide tube 11.5.5 Rotary table 11.5.6 Power tongs 11.5.7 Work basket and hydraulic workover control consoles 11.5.7.1 Operator‘s console 11.5.7.2 Assist operator’s console (in the work basket) 11.5.7.3 Remote operator‘s console 11.5.7.4 Remote blow out preventer console 11.5.8 Counterbalance winch 11.5.9 Gin-pole (telescoping mast) 11.5.10 Emergency evacuation of the work basket 11.5.11 Hydraulic power pack and accessory equipment 11.5.11.1 Main system pressure (jack pressure) 11.5.11.2 Blow out preventer and slip operation pressure 11.5.11.3 Counterbalance winch pressure 11.5.12 Hydraulic hoses 11.5.13 Fluid (circulating) system 11.5.14 Guy wires and support system 11.6 Well Control and Well Control Equipment 11.6.1 Barrier requirements and definitions (hydraulic workover) 11.6.1.1 Dead well barrier definitions 11.6.1.2 Live well barrier definitions 11.6.1.3 External barriers during live well operations 11.6.1.4 Live well operation: pipe internal pressure control 11.6.2 Single well, well control panel 11.6.3 Stripper bowl 11.6.4 Annular blow out preventer 11.6.5 Stripping blow out preventer and associated equipment 11.6.5.1 Spacer spool 11.6.5.2 Equalizing loop 11.6.5.3 Bleed-off or vent line 11.6.6 Blow out preventer ram preventers 11.6.7 Drilling spool 11.6.8 Lubrication 11.6.9 Blow out preventer control and operating system 11.6.10 Well control system accumulator requirements 11.6.11 Blow out preventer equipment configuration live well interventions 11.6.12 Blow out preventer equipment configuration: drawings 11.6.12.1 Example blow out preventer stack for live well interventions up to 5000psi (34,500kPa) working pressure: single p... 11.6.12.2 Example blow out preventer stack for live well interventions up to 5000psi (34,500kPa) working pressure: tapered ... 11.6.13 Tubing and workstring 11.6.13.1 Bending and buckling analysis 11.6.14 Workstring well control barriers 11.6.14.1 The full opening stabbing valve 11.6.14.2 Back pressure valves 11.6.15 Landing nipple 11.6.16 Plugging options where no nipple profile is available 11.6.17 Location of back pressure valves and nipple profiles in the bottom hole assembly 11.6.18 Downhole equipment 11.7 Operational Planning and Procedures 11.7.1 Well parameters 11.7.2 Prejob snubbing calculations 11.7.2.1 Snubbing force 11.7.2.2 Hydraulic cylinder pressure calculations 11.7.2.3 Pipe axial strength 11.7.2.4 Pipe burst 11.7.2.5 Pipe collapse 11.7.2.6 Buckling calculations 11.7.3 Pipe design factors 11.7.4 Selection of the workstring 11.7.5 Mitigating explosive potential 11.7.5.1 Explosive potential in the workstring/production tubing annulus 11.7.5.2 Explosive potential in the workstring 11.7.6 Specifying escape routes 11.7.7 Structural loads 11.7.8 Rigging up 11.7.9 Pressure testing and function testing 11.7.10 Setting the jack pressure 11.7.11 Tripping pipe 11.7.12 Crossing the balance point 11.7.13 Well suspension: daylight only snubbing operations 11.8 Well Control and Contingency Procedures 11.8.1 Power pack failure 11.8.2 Snubbing unit accumulator failure 11.8.3 Slip failure 11.8.4 Stripper ram seal failure 11.8.5 Annular seal failure 11.8.6 Leaking pipe ram 11.8.7 External leak on the christmas tree or wellhead or the BOP below the lowermost pipe ram 11.8.8 Bottom hole assembly check valve failure 11.8.9 Tubing leak above the bottom hole assembly 11.9 Why Well Control Matters References Twelve Well Control During Well Test Operations 12.1 Introduction 12.2 Industry Standards 12.2.1 Well test objectives 12.3 Well Offloading and Clean-Up 12.4 Well Test Surface Equipment 12.4.1 The wellhead to the choke manifold 12.4.1.1 Surface test tree or flowhead 12.4.1.2 Temporary flowline 12.4.1.3 Coflex hoses 12.4.1.4 Rig or facility permanent pipework 12.4.1.5 Data header 12.4.1.6 Sand detection 12.4.1.7 Sand filters and knock-out pots 12.4.1.8 Surface safety valve 12.4.2 The choke manifold to the separator inlet 12.4.2.1 The choke manifold 12.4.2.2 Steam heat exchanger and stem generator 12.4.2.3 The test separator 12.4.3 Diverter manifold to storage tanks, flowline or flare 12.4.3.1 Oil and gas diverter manifold 12.4.3.2 Atmospheric gauge tank 12.4.3.3 Surge tank 12.4.3.4 Burners 12.4.4 The emergency shut-down system 12.4.5 Surface equipment pressure rating 12.5 Well Testing: Downhole Equipment 12.6 Drill Stem Test Components 12.6.1 Bull-nose or mule shoe 12.6.2 Perforated joint or ported sub 12.6.2.1 Gauge (bundle) carrier 12.6.3 Debris sub 12.6.4 Gun release sub 12.6.5 Shock absorbers 12.6.6 Packers 12.6.7 Tubing test valve 12.6.8 Safety joint 12.6.9 Hydraulic jars 12.6.10 Relief valve and by-pass tool 12.6.11 Tester (shut-in) valves 12.6.12 Radioactive marker sub 12.6.13 Drill collars 12.6.14 Slip joints 12.6.15 Reverse circulating valve: single operation 12.6.16 Reverse circulating valve: multiple operation 12.6.17 Cross-overs 12.6.18 Tubing and drill pipe connections 12.6.19 Drill string test string design 12.7 Well Testing Operations 12.7.1 Barriers during a well test 12.7.2 Premobilization equipment check 12.7.3 On-site equipment checks 12.7.4 Pressure testing surface equipment 12.7.5 Brine and brine preparation 12.7.6 Running the drill string test string 12.7.7 Initiating production and the initial flow period 12.7.7.1 Cased and perforated wells 12.7.7.2 Open hole and barefoot completion 12.7.8 Opening up and flowing the well 12.7.9 Surface sampling 12.7.10 Downhole sampling and logging requirements 12.7.11 Killing the well 12.7.12 Pulling the drill string test string 12.8 Emergencies and Contingency Plans 12.8.1 Production shut-down at the host facility 12.8.2 Muster alarm (offshore installation) 12.8.3 Abandonment alarm or fire alarm (offshore installation) 12.8.4 Loss of containment: surface equipment 12.8.4.1 Leak on the swivel below the flowhead 12.8.5 Downhole leaks 12.8.5.1 Considerations and options 12.8.6 Downhole test tool failure 12.8.7 Hydrates References Thirteen Subsea Completion and Intervention Riser Systems 13.1 Introduction 13.2 Subsea Blow Out Preventer and Marine Riser Systems 13.2.1 System overview 13.2.2 The wellhead connector 13.2.3 Subsea blow out preventer stack 13.2.4 Lower marine riser package connector 13.2.5 Lower flex joint 13.2.6 Marine riser 13.2.7 Telescopic joint or slip joint 13.2.8 Marine riser tensioning system 13.2.9 Kill and choke lines 13.2.10 Choke and kill line “failsafe” valves 13.2.11 Subsea blow out preventer control systems 13.3 Subsea Wellhead Systems 13.3.1 Wellhead components 13.3.2 Conductor housing, temporary guide base, and permanent guide base 13.3.3 Wellhead housing 13.4 Subsea Well Construction 13.5 Wellhead Integrity 13.6 Subsea Trees 13.6.1 Conventional dual bore vertical trees 13.6.2 Enhanced (large bore) vertical tree 13.6.3 Horizontal subsea trees (spool tree) 13.7 Subsea Tree Riser Systems 13.7.1 Vertical tree (dual bore 5in.×2in.) 13.7.1.1 Tubing hanger running tool 13.7.1.2 Tubing hanger orientation helix 13.7.1.3 Completion landing string 13.7.1.4 Lower marine riser package 13.7.1.5 Emergency disconnect package 13.7.1.6 Dual bore riser 13.7.1.6.1 Stress joint 13.7.1.6.2 Standard riser joint(s) 13.7.1.6.3 Tension joint 13.7.1.6.4 Surface joint 13.7.1.6.5 Surface test tree 13.7.2 Enhanced vertical tree (mono-bore) 13.7.3 Horizontal tree riser and re-entry system 13.7.3.1 Horizontal tree: tubing hanger running tool 13.7.3.2 Subsea test tree 13.7.3.3 The landing string 13.7.3.4 Surface test tree 13.8 Subsea Intervention and Workover Control Systems 13.8.1 Direct hydraulic control 13.8.2 Piloted hydraulic control 13.8.3 Hard-wired electrohydraulic controls 13.8.3.1 Multiplexed electrohydraulic References Fourteen Well Control During Subsea Completion and Workover Operations 14.1 Subsea Well Control 14.1.1 Kick detection 14.1.2 Effects of water depth on reservoir fracture pressure 14.1.3 Riser margin 14.1.3.1 Oilfield units 14.1.3.2 Metric units 14.1.4 Kick tolerance 14.1.5 Choke line friction 14.1.6 Pressure changes at the choke when gas reaches the choke line 14.1.7 Handling trapped gas in the blow out preventer stack 14.1.8 Riser kill 14.2 Shut-In Procedure 14.2.1 General shut-in procedures: drill pipe 14.2.2 Shut-In procedure whilst circulating 14.2.3 Shut-In procedure while tripping 14.3 Shut-In Procedures Whilst Running or Pulling a Completion 14.3.1 Running sand control screens or slotted liner 14.3.2 Running control lines and instrument cables 14.3.3 Pulling spent tubing-conveyed perforating guns 14.3.4 Pulling damaged completion tubing 14.4 Pre-workover: Planned Well Kill 14.4.1 Establishing a circulation path 14.4.2 Handling hydrocarbons 14.4.3 Riser disconnect 14.4.4 Planned (nonemergency) disconnect 14.4.5 Emergency (unplanned) disconnect 14.4.6 Reentering a well following a disconnect 14.5 Subsea Interventions 14.6 Rigging Up Using a Coiled Tubing Lift Frame 14.7 Wellbore Access: Horizontal Trees 14.8 Wellbore Access: Vertical Trees 14.9 Well Control During Subsea Intervention Operations 14.9.1 Roles and responsibilities 14.9.1.1 Drill crew 14.9.1.2 Subsea test tree vendor 14.9.1.3 Well testing vendor 14.9.1.4 Subsea Christmas tree vendor 14.9.1.5 Wireline crew (slickline and logging) 14.9.1.6 Coiled tubing crew 14.9.1.7 Stimulation crew and stimulation vessel 14.9.2 Riser and landing string preparation 14.9.2.1 Horizontal tree system 14.9.2.2 Vertical tree system 14.10 Intervention Riser Disconnect 14.10.1 Riser disconnect: horizontal tree 14.10.1.1 Planned disconnection 14.10.1.2 Planned disconnection with intervention tools in the well (coiled tubing or wireline) 14.10.1.3 Emergency disconnection 14.10.2 Riser disconnect: vertical tree 14.10.2.1 Controlled disconnect 14.10.2.2 Emergency disconnect 14.11 Additional Well Control and Well Integrity Considerations for Subsea Intervention Operations 14.11.1 Hydrate prevention 14.11.2 Wireline operations 14.11.3 Riser or landing string leak 14.12 Coiled Tubing Operations 14.12.1 Rig heave 14.12.2 Production shut-down 14.12.3 Injector replacement 14.12.4 Riser or landing string leak 14.12.5 Collapsed pipe 14.12.6 Releasing stuck coiled tubing using a chemical or explosive cutter 14.12.7 Tubing parted downhole 14.13 Stimulation Operations: Working With Frac Boats 14.14 Well Testing Operations 14.14.1 Leak between the subsea test tree and the surface test tree Fifteen Subsea Wireline Lubricator Interventions 15.1 Mono-Hull Intervention Vessels 15.2 The Derrick 15.3 Subsea Intervention Lubricator Systems 15.3.1 Grease head or liquid seal stuffing box 15.3.2 Grease head latch mechanism 15.3.3 The lubricator 15.3.4 Lower base section or well control package 15.3.5 Control system 15.3.6 Main control panel 15.3.7 Tree bore selectivity 15.3.8 Tree running tool 15.4 Operations With the Subsea Lubricator 15.5 Lubricator Deployment 15.6 Wireline Well Entry 15.6.1 Wireline operations on wells equipped with vertical trees 15.6.2 Wireline operations on wells equipped with horizontal trees 15.7 Wireline Operations: Well Control Procedures 15.7.1 Leaking pressure control equipment 15.7.2 Horizontal tree 15.7.3 Vertical tree operations 15.7.4 Tool string stuck in the well 15.7.5 Wire parts above the grease head 15.7.6 Wire parts downhole 15.7.7 Hydrate formation 15.7.8 Vessel drive off (unplanned) 15.7.9 Planned disconnect Reference Index