BJ Coiled Tubing Equipment Manual Version 1
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BJ Services Tomball EDC- Training Department
TCC210 COILED TUBING EQUIPMENT CORRESPONDENCE COURSE
EDC – Tomball, Version 1.01 Revised: April 2005
BJ Services Tomball EDC- Training Department
Copyright 2005, by BJ Services. All Rights reserved. No part of this manual may be reproduced in any form or by any means (including electronic storage and retrieval or translation into a foreign language) without prior agreement and written consent from BJ Services as governed by United States and international copyright laws
Training Department BJ Services 11211 FM 2920 Tomball TX 77375 Printing History: First Edition – April 2005 Credits: Training Department:
Tim Ramsey, Training Engineer; Jim Wilke Manager Engineering Training Group; Ken Kenner Manager Corporate Training
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INDEX Subject
Page
Introduction History of CT CT Reel Injector Head Gooseneck Power Pack Control Cabin Well Control Equipment Bottom Hole Assemblies CT Manufacturing CT Fatigue CT Selection Criteria Circa Cycle Monitoring Equipment Health & Safety
4 5 7 12 17 18 20 22 32 69 75 80 83 85 87 89
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Coiled Tubing Equipment ___________________________________________________________________________________
Introduction This article was developed with the intention to be a guide for the correspondence course TCC210, which forms part of the T-CAP training plan in BJ Services Company. It presents an overview of the coiled tubing equipment, necessary to perform a coiled tubing intervention either on land or offshore. Over the past decade the number of applications for coiled tubing services within the petroleum industry has been increasing exponentially and coiled tubing services continues to be one of the fastest growing sectors in the industry. BJ Services currently owns and operates about one hundred fifty five (155) Coiled Tubing Units worldwide - Second largest World CTU Fleet, of which more than half are operated on land. Coiled tubing growth has been driven by economics, continual technological advances and the successful utilization of CT to perform an ever-growing list of field operations. • • • • • • • • • • • • •
Gas Lifting Stimulation – Fracturing & Acid treatments Fill Cleanouts Cementing Scale Removal Workover Drilling / Milling Electrical Applications – Logging & perforating Fishing Force Application Ultra-high Pressure Pipeline Servicing Permanent Installations – Completions & Gravel Packs Vertical / Horizontal Under Balanced Drilling – DUCT
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The advantages associated with coiled tubing are: • The ability to operate on live wells – does not require well to be killed, thus reducing risk of formation damage. • Quick mobilization and rig up. • Ability to work Rigless – no associated rig costs. • Reduced surface footprint and crew configuration. • Efficient offshore mobilization – skid mounted units. • Ability to perform operations while well is producing – minimizing production downtime. • No connections and thus ability for continuous circulation during live well intervention.
The History of Coiled Tubing Extracted from World Oil’s Coiled Tubing Handbook, 1993
In 1944 the first coiled tubing pipeline treatment was executed; Project PLUTO (PipeLines Under The Ocean). The job consisted of laying 23 three-inch (76.2 mm) diameter pipelines across the English Channel to supply allied forces with fuel to sustain the liberation of occupied Europe during World War II. Each pipeline consisted of pre fabricated 4,000 ft (1219 m) sections of pipe, butt-welded together and spooled onto 40 foot (12.2 m) hub diameter reels. Of the 23 pipelines, 17 were about 30 mi. (48.3 km) long and the remaining six were 70 mi. (112.6 km) long. Injector head designs were first developed for use with submarines. In the early 1960’s Bowen Tools was contracted to deploy a radio antennae from submarines. The concept was very similar to that of a coiled tubing injector. In 1962 the California Oil Company and Bowen Tools developed the first coiled tubing unit. The unit was called a ‘continuous-string light workover unit’. The size of pipe used was 1.315” OD. The coiled tubing was fabricated from 50ft segments. The steel used was low alloy Colombian tubing. The 50ft segments were butt-welded and spooled onto a 9ftdiameter work reel with a total length of 15,000 ft. Through 1963 and 1964 this unit performed numerous jobs in the Louisiana area. The continued development of coiled tubing may be described as follows: • 1964: Brown Oil Tools and Esso introduce a new coiled tubing injection system. The unit was built to run ¾” coiled tubing. EDC – Tomball, Version 1.01 Revised: April 2005
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• 1967: Bowen introduces a downsized version of the original injector design. The injector is the 5M capable of handling 5,000 lb. of ½” coiled tubing. NOWSCO contracted Bowen Oil Tools to build 12 “5M” coiled tubing units. • 1968: Bowen developed the “8M” coiled tubing injector head capable of running 8,000 lb. of ¾” coiled tubing. • Late 1960’s to mid 1970’s: Modifications and new designs for coiled tubing units. The common size of coiled tubing in use increased to 1” OD More than 200 coiled tubing units were built in this time frame. • Late 1970’s: New coiled tubing equipment manufacturers emerged; Uni-Flex Inc., Hydra Rig Inc., Otis Engineering. The new injectors built were similar to that of Bowen Tools. • 1975: Uni-Flex introduces a new injector head design. Many of the new features influenced future injector designs of other manufacturers. • 1976: Formulation of Quality Tubing Inc., with financial assistance from NOWSCO. • 1978: All construction of Uni-Flex and Brown Oil Tools coiled tubing equipment was stopped. • Late 1970’s to early 1980’s: Many design changes and revisions made to improve coiled tubing equipment. The main suppliers of coiled tubing units were Bowen Tools, Hydra Rig Inc. and Otis engineering. • 1985: New coiled tubing injector developed by Fleet Cementers, capable of supporting 8,500 ft of 1¾” coiled tubing. • 1989: Quality Tubing Inc. awarded patent for bias weld procedure. This dramatically improved the fatigue life of the coiled tubing. • 1993: Quality Tubing received a product patent for continuous coiled tubing. • Dec. 1999 Coiled Line Pipe now established as an API Product
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Generally speaking, a Coiled Tubing unit is made up of six basic components: 1. 2. 3. 4. 5.
Tubing Reel. Injector Head & Gooseneck Power Pack. Control Cabin. Well Control Equipment. • Stuffing Box (Stripper, Packoff). • Blow-Out Preventers (BOP).
The Coiled Tubing Reel Coiled tubing is stored on a drum that is supported on a shaft and mounted on a skid frame. A bi-directional hydraulic motor directly driving the reel via roller chain and sprockets or by a gear drive system rotates the reel. The drive system has dual function: when running in hole (RIH), the motor acts as a constant-torque brake, enabling back tension to be held on the pipe and while pulling out of hole (POOH), more tension is applied to enable efficient spooling of the pipe onto the drum. The reel will have a brake mechanism to prevent accidental rotational movement when it is required. The reel drive system should produce enough torque to provide the required tension to the coiled tubing to bend the coiled tubing over the gooseneck and onto the reel. This tension provided by the reel on the coiled tubing unit between the reel and injector is commonly referred to as ‘reel back-tension’. The tension requirements – thus reel motor drive system- increases exponentially with coiled tubing diameter because of the increased load/weights required. Note: This tension is not intended to aid the injector head in pulling the coiled tubing from a well. The tubing is spooled on/off the drum using a hydraulically raised & lowered levelwind assembly. The levelwind allows for travel along an adjustable diamond lead screw and is powered by rotation of the reel itself and incorporates a floating tubing guide to allow for height adjustments. A manual override facility is incorporated to allow for compensation of spooling errors.
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Levelwind Assembly Floating Tubing Guide
Reel CT Oiler System
Figure 1 Coiled Tubing Reel
Reel Motor
Lead Screw
Figure 2 Coiled Tubing Levelwind Assembly
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The reel is equipped with a rotating joint (swivel) to allow pumping through the coiled tubing while the reel is rotating; this rotating joint is flange mounted onto the reel shaft. The inboard end of the coiled tubing is connected to drums external iron plumbing, via a welded 1502 WECO thread External plumbing may consist of: • 2” Fig1502 chicksan • 2” Fig1502 tee • 2” Fig1502 plug valves CT connection to reel iron • Pig launcher assembly Pig Launcher Bleed Off Valve
Rotating Joint Plug / Ball Insertion Port and Plug
Stopper Pin Keeps ball or plug from falling backwards prior to pumping
Pressure Transducer
Reel Iron Manifold
Figure 3 Rotating Joint
Figure 4 Reel Iron Manifold
For operations where the offshore platform crane limit is a problem, Drop in Drums can be shipped as two separate loads. The drum with the coiled tubing is sent as one load and the support frame as a second load. Once the two separate sections have been lifted onto the platform, the spool is then fitted into the support frame. The spooler is fitted with the same pumping facilities as the standard reel and can also facilitate e-line coiled tubing.
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The length of coiled tubing of a certain size, which can be stored on a reel, is known as the reel capacity. The reel capacity differs for different coiled tubing size. Consideration should also be referenced to the reels Core Diameter and its bending radius – reference COP’s manual aforementioned extract. Examples of CT Drum sizes and capacities: Diameter (in) Core Flange Drum Width
60 100 60
76 119 70
84 135 70
84 148 70
Gross Lift Capacity (lbs)
30,000
48,000
68,000
68,000
96 168 82 115,000
Tubing Capacity (ft) CT OD (in) 1.25 1.5 1.75 2 2.375
15,000 10,000 -
22,500 15,100 11,200 8,500 -
25,000 22,000 15,000 11,000 -
25,000 25,000 20,000 15,000 -
25,000 25,000 25,000 22,000 15,000
Diameter (cm) Core Flange Drum Width
152.4 254.0 152.4
193.0 302.3 177.8
213.4 342.9 177.8
213.4 375.9 177.8
243.8 426.7 208.3
Gross Lift Capacity (kgs)
13,608
21,772
30,844
30,844
52,163
Tubing Capacity (m) CT OD (mm) 31.8 38.1 44.5 50.8 60.3
4,572 3,048 -
6,858 4,602 3,414 2,591 -
7,620 6,706 4,572 3,353 -
7,620 7,620 6,096 4,572 -
7,620 7,620 7,620 6,706 4,572
Depth Measurement: A mechanical odometer for depth measurement with 5-digit read out is usually installed on the level wind assembly. The measured depth is the length of coiled tubing that is deployed below the injector head into the well. The measured depth can be directly measured in several places on a coiled tubing unit using a friction EDC – Tomball, Version 1.01 Revised: April 2005
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wheel, which is in contact with the coiled tubing. Other than the reel, a depth counter may be installed on the injector or the gooseneck. Depth can also be obtained indirectly by measuring the rotation of the injector head gear drive shafts. It should be noted that measured depth might be different to actual depth of the coiled tubing due to the following, well profile and the helical effect, thermal expansion, stretch and counter efficiency. CT Reel Minimum Purchase Standards – Extracted from BJ Services CT Operations & Procedures (COP’s Manual) • • •
• • • • • • • • • • •
The drive system must have a higher top speed than the injector The shaft torque should be 1.5 times the line pull required for the biggest, heaviest coil to be utilized The minimum core diameter needs to be forty-eight (48) times the maximum pipe OD to be run on the reel. As large as possible i.e. 1.25” / 72”, 1.50” / 90”, etc. (31.8 mm / 182 cm, 38.1 mm / 228 cm) Dynamic and mechanical reel brakes are required The levelwind needs to be able to handle 80 degrees of elevation The internal piping needs to be integral and have a minimum 10,000 psi (70,000 kPa, 690 bar) working pressure rated with at least one plug valve and ball drop “Tee”. The rotating joint shall be rated at 10,000 psi (70,000 kPa, 690 bar) working pressure. The rotating joint to have a non obstructed ID equivalent or larger than the maximum coil ID except 2 7/8” (73 mm) and 3 1/2”(88.9 mm) All reels shall be counter drilled for “Stiff Wireline” applications. The plug launcher shall be part of the internal plumbing. There shall be a hydraulic fail-safe clamp on the levelwind. A mechanical depth counter shall be mounted on the levelwind. A pipe lubrication system, non hand spray, will be located somewhere on the unit (i.e. the stuffing box or levelwind) Reel capacity is not the same for different coiled tubing sizes. Capacity for any given reel can be calculated as follows; L = ((A-F)/D) X (B/D) X (2C+B)/3.82 L = Reel capacity (feet) A = Reel flange height (inches) F = Reel free board (inches) D = Coiled Tubing diameter (inches) B = Width of reel between flanges (inches) C = Core diameter (inches)
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Coiled Tubing Injector Head The injector head is the heart of the coiled tubing unit. This piece of equipment allows the coiled tubing to be injected (snubbed) and retrieved from the wellbore. Injector head manufacturers include Hydra Rig, Stewart & Stevenson, Bowen, Maritime Hydraulics, Dreco and others; H-R and S & S are considered the two current market leaders. The coiled tubing is gripped between contoured blocks, which are carried by two sets of double row contra-rotating chains. The injector operates on the friction drive principle. The injector speed and direction are controlled through the use of bi-directional hydraulic motors that provide the force for the injector. Hydraulic motors are used to drive the gripper block and chains by turning the chain drive sprockets. Different configurations are available with up to four motors driving the upper and lower sprockets. The hydraulic counter balance system provides dynamic braking when hydraulic pressure is released. Many injector motors have built in hydraulically released mechanically actuated brakes that automatically lock when there is loss off hydraulic pressure to the motor. Separate external manual mechanical brakes are also used on older injector heads. It is important that correct tension of the drive chains be maintained to prevent either crushing the tubing, or letting it slip due to poor grip.
Chain Drive Sprockets
Outside Chain Tension Cylinder
Gripper Block Traction Cylinders
Contra-rotating chains
Figure 5 Injector head Blocks & Chain System
The chains and their motor and gearbox drive system are mounted in a subframe, one side of which is hinged. The opposite lower side can rest on a hydraulic load cell, which is connected to the weight indicator in the control cab. The forces EDC – Tomball, Version 1.01 Revised: April 2005
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exerted by the action of the drive system and the tubing weight are all applied along the centerline of the tubing and cause the subframe to pivot; the resulting deflection measuring direct force or load acting on hydraulic load cell bladder. Individual hydraulic load cells will measure either pipe-heavy (positive weight) or pipe-light (negative weight, less than zero, snubbing). Another type of weight indicator is an electric strain gauge model. This type of weight indicator measures the applied load by strain gauges, with output signals in mAmps (4-20mA) or Volts (0-5 V), which are converted in the cab to measure applied loads – tension (pulling) or compression (snubbing). The load is defined as the tensile or compressive force in the coiled tubing just above the stripper. It is one of the most important measurements used in the operation of a coiled tubing unit. Load may be effected by several parameters other than the hanging weight of the coiled tubing, including wellhead pressure, stripper friction, reel back-tension, gooseneck alignment and the density of the fluids inside and outside the coiled tubing. Note: Reference individual unit manuals for hydraulic pressure to Lbs. pull/snub ratios, to ensure correct operating guidelines and to cross-reference weight indicator reading with hydraulic pressure applied to the injector motors. CT Weight
Pivot
Pipe Heavy
Pipe Light
Figure 6 & 7 Injector Head Pivot and Load Cells
Pipe Light load Cell
Pipe Heavy load Cell
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Figure 8 Injector Gripper Blocks & Chain
Figure 9 Injector head & Gooseneck
Mechanical Depth Counter
Depth Encoder
Figure 10 Injector Head Mechanical Counter & Encoder
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EXAMPLES of HYDRA RIG INJECTOR HEAD CAPABILITIES
HR-125
HR-150
HR-240
HR-260
HR-420
HR-440
HR-480
HR-5100
HR-5200
Maximum Rate Pull - (lbs.)
32,000
42,000
40,000
60,000
18,000
60,000
100,000
100,000
200,000
Maximum Snub Capacity -( lbs.)
10,000
10,000
15,000
15,000
5,000
20,000
40,000
60,000
60,000
Tubing Size Capacity - (in.) Minimum CT OD Maximum CT OD
1.00 1.75
1.00 2.375
1.00 1.75
1.00 2.375
1.00 1.25
1.00 2.375
1.25 3.50
1.25 3.50
2.00 5.50
Approx. Weight w/Gooseneck- (lbs)
7,500
10,000
8,000
11,000
3,600
7,200
13,500
11,500
11,500
HR-125
HR-150
HR-240
HR-260
HR-420
HR-440
HR-480
HR-5100
HR-5200
Maximum Rate Pull - (daN.)
14,234
18,683
17,793
26,689
8,007
26,689
44,482
44,482
88,964
Maximum Snub Capacity -(daN.)
4,448
4,448
6,672
6,672
2,224
8,896
17,793
26,689
26,689
Tubing Size Capacity - (mm.) Minimum CT OD Maximum CT OD
25.40 44.45
25.40 60.33
25.40 44.45
25.40 60.33
25.40 31.75
25.40 60.33
31.75 88.90
31.75 88.90
50.80 139.70
Approx. Weight w/Gooseneck- (kgs)
3,402
4,536
3,629
4,990
1,633
3,266
6,123
5,216
5,216
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Injector Head Minimum Purchase Standards– Extracted from BJ Services CT Operations & Procedures (COP’s Manual) • •
•
• • • • • • • • • • • • • • • •
•
A minimum of 50% snubbing capability verses pulling. Snubbing force which is 120% of the maximum anticipated by the Circa prediction both while the coiled tubing is stationary and while it is moving at speeds up to 30 ft/min (10 meters/min) A dynamic braking system that prevents the coiled tubing from moving when no hydraulic pressure is being applied to the hydraulic motors. Also a secondary mechanical brake which is set automatically or manually when the injector is stopped. Braking systems must be capable of holding the maximum pulling force and the maximum snubbing force. The chains should be able to achieve maximum pull without the aid of coatings. The ability to change pipe size without the need to remove the chain (i.e. inserts). The maximum speed should be 240 ft/min. (70 m/min) Some means of support to prevent loads being transmitted to the wellhead. Note: The base must be strong enough to support the load of tubing suspended in the well as well as the injector. The injector frame and pad eyes rated to the injector weight plus the maximum rated pull. An accumulator on the skate traction hydraulic system. An adjustable mounting system for the gooseneck. The load cell shall be dual acting. The weight indicator will have “heavy/light” readings when rated above 50,000 lbs (22,200 daN) or is electronic. A chain tensioning system A drip tray to catch and contain chain lubrication Pad eyes for lateral re-strainment A ladder for access to the gooseneck A non-slip cover on top of injector The ability to pull test to 120% of the maximum anticipated by CIRCA prediction, while stationary and while the coiled tubing is moving at 30 feet/min (10 m/min) Must have a maintenance odometer installed.
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Gooseneck: To complete the injector head package there is a tubing roller guide or gooseneck positioned on top off the injector head. The gooseneck aids in supporting, straightening and aligning the coiled tubing as it comes off the work reel and into the gripper blocks on the injector. This is done by a series of contoured rollers and cages that contain the coiled tubing as it travels over the gooseneck. The gooseneck base should also pivot or be flared at reel facing end, to enable for spooling across a work reel as the coiled tubing travels along the width of the drum. The gooseneck is designed with a nominal radius of curvature appropriate to the coiled tubing size; the radius needs to be at least 48 times the coiled tubing OD. This is to enable the maximization of coiled tubing life and thus reduce the effect of fatigue. Common gooseneck sizes are: 72”, 96” and 120”(183 cm, 243cm and 305cm).
Figure 8 Gooseneck Sizes
Figure 9 Gooseneck Roller
Gooseneck Minimum Purchase Standards– Extracted from BJ Services CT Operations & Procedures (COP’s Manual) •
Needs to be adjustable. The pipe should enter and exit the guide arch tangent to the curve of the guide arch • The guide arch radius needs to be at least 48 times the coiled tubing OD. Note: A radius larger than 100 inches (254 cm) does not gain significant advantages. • The closer the rollers are spaced, the better. • The gooseneck needs to be strong enough to handle the combined bending of the pipe, withstand the bending moment that maximum reel back tension would apply and a 5% side moment (fleet angle) that happens when you are spooling at the extreme sides of the reel. • The end of the gooseneck should be flared. This flare should accommodate the maximum fleet angle that it will see without the pipe seeing another strain reversal.
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Coiled Tubing Power Pack The most common type of power pack is diesel driven skid/trailer unit made up of a system of hydraulic pumps, hydraulic pressure control circuits, hydraulic tanks and accumulators to enable the efficient operation of the coiled tubing package. Power packs are built in many different configurations depending on the operating environment e.g. Electric Units, Zone 2 Certified, Sound Proof, ‘Wet Units – trailer tractor driven’ etc. The type of injector drive circuit generally classifies power packs: • Standard Open Loop Power Pack – The standard open loop injector drive circuit utilizes a fixed displacement double vane pump and a 4-way valve. The valve is a pressure compensating directional control valve that controls the speed and direction of the injector motors. The system is capable of operating at 3,000 psi. (20,684 kPa) and works on the principle of oil going from the tank, through the pump and valves and to the injector motors; oil returns through a filter and air cooler into the hydraulic tank. • High Pressure Open Loop Power Pack – The high pressure open loop injector drive circuit utilizes a load sensed, variable displacement, pressure compensated piston type pump. The system is capable of operating at 5,000 psi. (34,473 kPa) and works on the principle of oil going from the tank, through the pump and valves and to the injector motors; oil returns to the pump inlet (supercharging the pump) after passing through a filter and heat exchanger. A pressure relief valve in the return line ensures oil that is not required by the pump is routed back to the tank; an advantage of this system, is that less heat is generated. • Closed Loop Power Pack – The closed loop injector circuit utilizes a bidirection, variable displacement pressure compensated piston pump. The pump actually comprises of three pumps: main pump, charge pump and servo pump (shifts the swash-plate for directional control). The system is capable of operating at 5,000 psi. (34,473 kPa) and is a less complicated system when compared to the high-pressure open loop system. The system works on the principle of oil going from the tank, through the pump and valves and to the injector motors; oil returns through a filter and goes directly back to the pump inlet. A charge pump and auxiliary flushing circuit are always present to replenish fluid that leaked from the high pressure elements into the pump’s case and to add cool oil into the low side of the loop to stabilize the oil temperature. EDC – Tomball, Version 1.01 Revised: April 2005
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Hydraulic Circuit Injector Flush Reel Levelwind BOP Priority Auxiliary
Function Runs the injector Flushes injector (Closed loop pumps only) Runs the reel Runs the levelwind Runs the BOP system Runs the controls in the control cabin Runs the powered hose reels, crane, winch etc.
Figure 10 Skid Mounted Power Pack
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Coiled Tubing Control Cab The control cabin fully allows the operation and control of all functions of the coiled tubing unit from within the cabin. The typical unit is hydraulically elevated for better operator vision. The control panel incorporates: • • • • • • • • • • •
Injector controls Reel controls Dual stripper packer controls BOP controls Auxiliary shear seal BOP controls Hydraulic circuit pressure gauges Weight indicator Coiled tubing internal pressure Wellhead pressure - WHP Data Acquisition unit Remote power pack control
The unit is fully insulated with a heater for cold climates and space for air conditioning unit in warm climates. All necessary hoses to control and operate the Injector Head, BOP’s, Power Pack and Tubing Reels are incorporated on hydraulically powered reels on the front of the skid.
Figure 11 Example of Control Cab Interior
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Power Pack and Control Cab Minimum Purchase Standards– Extracted from BJ Services CT Operations & Procedures (COP’s Manual)
• • • • • •
The engine size needs to be able to handle the injector plus the auxiliary systems at maximum load with a 50% safety factor. The hydraulic system to be able to dissipate maximum heat output. The control cab window shall be protected or have bullet proof glass. The blind and shear ram controls on the control panel shall have positive locks. The accumulator charge shall be sized to handle Close, Open, Close scenario of all rams at the maximum BOP rated working pressure. The hydraulic system for the BOP’s and stuffing box shall have two back-ups (i.e. air and manual).
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Well & Pressure Control Equipment Coiled tubing well and pressure control equipment is designed to allow for safe well intervention on a live/pressurised well. The stuffing box and BOP are considered a Primary barrier for well control purposes. Stuffing Box The stuffing box is the primary sealing mechanism for isolating/containing wellbore fluids while coiled tubing is under static or dynamic operating conditions. The stuffing box is attached to the bottom of the injector head by means of a flange connection or retaining pins. Operation of the stuffing box is by means of hydraulic pressure acting on a piston, which compresses a polyurethane element (stripper rubber) forming a seal around the coiled tubing. The packing elements are positioned between sets of brass bushings and may incorporate Non-Extrusion Rings between bushings and stripper element. There are two main stuffing box designs: 1. Top Loading: This is the original (older models) stuffing box design used for coiled tubing operations. The packing elements are positioned between sets of brass bushings. A double acting piston compresses the bushings together to squeeze the stripper rubber around the coiled tubing. The upper section of the stuffing box is called the split cap and comprises of split housing containing the upper wear bushings. The split cap is held in place with retaining pins or it is threaded into the body. The design allows for the stripper rubbers to be changed out if required during a well intervention by taking out the split cap (not as user friendly as side door design.) 2. Side Door: This design allows the packing elements to be replaced through a door below the injector-mounting interface. Changing elements with this design is easier and safer when changing elements with coiled tubing in the well. The side doors are unlocked and swing open and then the piston is retracted to expose the stripper elements – enabling them to be swapped out. Common stuffing box bore sizes: 2.50”, 3.06” and 4.06” (63.5 mm, 77.7mm and 103mm). EDC – Tomball, Version 1.01 Revised: April 2005
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Stuffing Box connected to Injector Head
Figure 12 Top Loading Figure 13 Stuffing Box & Injector
Doors Stripper Rubber
Figure 13 Side Door
Figure 13 Retracting Side Door Entry
Top Bushings Non-Extrusion Rings Stripper Rubber
Bottom Bushings
Figure 14 Internal Elements
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Note: Two causes of excessive stripper rubber wear are dry, rusty pipe and dry gas. Lubricating the coiled tubing prior to it going into the stuffing box will reduce the wear on the element; this can be done by lubricating the tubing at the reel or utilizing an adapted stuffing box with an inhibitor injection port. The positioning of the top of the stuffing box should be kept close as possible to the bottom of the injector chains to help prevent buckling of the coiled tubing while running in hole (minimize void between the bottom of the gripper blocks & chains and the top of stuffing box). This is usually achieved by adding an Anti-buckling device (extra set of bushings) which reduces the gap to approximately 4 inches.
Figure 15 Stripper Rubber
Stuffing Box Minimum Purchase Standards– Extracted from BJ Services CT Operations & Procedures (COP’s Manual)
• •
Approved vendor Complies with or exceeds NACE MR 0175 and API standards for well control equipment • Minimum 10,000 psi (70,000 kPa, 690 bar) working pressure with a 15,000 psi (100,000 kPa, 1032 bar) test pressure • H2S compatible • Have an injection port below the pack-off • Have a “chemical injection port” above the packer elements to allow 360ºcoverage of the pipe with a wide variety of anti corrosion chemicals or lubricating oils Preference is given to : • Systems where the distance from the top of the upper bushings to the chains is minimized • “Side removable” packer element designs (i.e. side-door, radial, etc.) • Dual acting hydraulic pack-off, ones that hydraulically energize and release • The hydraulic energizing system should have “weep holes” to signify worn orings/seals • Benoil is the only approved stuffing box packer/energizer vendor for wellhead operation with pressures exceeding 3000 psi (21000 kPa) and or temperatures exceeding 2120 F (1000 C)
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Blow Out Preventers – BOP’s The BOP is the primary safety apparatus designed to prevent the uncontrolled release of wellbore hydrocarbons and is usually flanged on top off the wellhead. A coiled tubing BOP is designed specifically for coiled tubing operations. The BOP consists of several pairs of rams, with each pair of rams having a specific function. 1. Blind rams isolate and seal against open hole when there is no tubing in the BOP. 2. Shear or Cutter rams have cutting blades to shear the coiled tubing and wire, if stiff-wireline. A Booster cylinder may be incorporated in the ram system to aid in shearing larger diameter or heavy wall coiled tubing. 3. Slip rams hold the coiled tubing to prevent it from being pushed out of the well or from falling down the well. Note Interrupted Slip Inserts are recommended to prevent undue marking of the tubing in event of use of rams. 4. Tubing or Pipe rams form a pressure seal around the coiled tubing to isolate well bore and contain pressure. The number and type of ram pairs in a BOP is determined by the configuration: • Single • Double • Triple • Quad
Blind/Shear Rams Blind Rams
Shear Rams
Slip Rams Pipe Rams Pipe/Slip Rams
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Minimum pressure rating for new BOP’s is 10,000 psi (68,947 kPa) and 15,000 psi (103,421 kPa) working pressure. The Quad BOP has two equalizing ports, one on each sealing ram – their function is to equalize pressure across the ram face if required. The BOP will also have a pump in side outlet in-between the slip and shear rams, to enable well killing/pumping facility if operationally required. Note this port is not to be used as a flow-line or take returns.
Blow-out Preventer Sizes BOP Size - (in)
2.56
3.06
4.06
5.12
6.38
7.06
Tubing Size - (in.) Minimum CT OD Maximum CT OD
0.75 2
0.75 2.375
1 2.875
1.25 3.50
1.25 3.50
1.25 3.50
BOP Size - (mm)
65.02
77.72
103.12
130.05
161.93
179.32
Tubing Size - (mm.) Minimum CT OD Maximum CT OD
19.05 51
19.05 60
25.40 73
31.75 89
31.75 89
31.75 89
Blind Ram
Slip Ram
Pipe Ram Shear Ram Figure 16 Ram insets Figure 18 Quad BOP
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Figure 18 Interrupted Slip inserts
BOP Minimum Purchase Standards– Extracted from BJ Services CT Operations & Procedures (COP’s Manual)
• • • • • • • • • • • • • • • • • •
Approved vendor Complies with or exceeds NACE MR 0175 and API standards for well control equipment Minimum 10,000 psi (70,000 kPa, 690 bar) working pressure with a 15,000 psi (100,000 kPa, 1032 bar) test pressure Minimum 3 1/16” (77 mm) ID All shall be H2S compatible All BOP hoses will be fire proofed the first 50 feet (15 m) from the well All rams to be able to close in 15 seconds or less at minimum temperature Minimum configuration will be blind, shear, slip and pipe or combination of these Have a kill port with a minimum 2 1/16” (52 mm) flange Ability to monitor wellhead pressure below the pipe rams Pressure equalizing valves across all pressure containing rams Use of only flanged/metal-to-metal connections below the lowest blind rams Slip design shall minimize fatigue/deformation damage (interrupted profile, diamond or other pattern) Slip rams shall be capable of holding the pipe up to the minimum yield point at the maximum rated working pressure in a hang-off mode. In a “snub” mode, the should hold a minimum of 50% of the minimum yield of the coiled tubing Have shear/seal feature Shear rams capable of shearing the heaviest wall and highest yield OD pipe the BOP is designed to accommodate at its maximum rated working pressure. Hydraulic pressure utilized to make this cut will be less than 3000 psi (21,000 kPa, 206 bar) Shear rams shall be capable of two or more successive cuts of the above pipe while still leaving a fishable profile plus flow path through the pipe Shear rams must be capable of cutting slick or braided line cleanly
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• • •
All rams to have a manual locking device capable of holding maximum working pressure ratings as well as hydraulic operating pressure. The rams can only be opened hydraulically after the lock has been disengaged Accumulator should be sized to operate all rams one-and-a-half cycles (close, open close) at the maximum rated BOP working pressure All BOP’s will have telltale weep holes. Reason: If a seal fails the well fluids or gasses will leak at the BOP rather than travel through the system back to the hydraulic reservoir at the unit
Auxiliary Well Control Equipment Hydraulic Quick Latches Installed between the coiled tubing BOP and the stuffing box or riser, the hydraulic quick latch provides a safe and easy method of injector rig-up. The device will incorporate a tapered seal bore that facilitates the stabbing/making the connection. When fully connected the quick latch provides a positive engagement on the locking dogs as well as an external indicator. An example of a quick latch is the Texas Oil Tools HydraConn. The quick latch is safer and saves time, as the operator does not need to stand and use their hands to align the flange or quick union. Annular BOP’s The annular BOP will close and seal blind on wireline, bottom hole assemblies and coiled tubing up to full-bore. Designed primary as a static sealing element it will allow stripping into or out of the well. The annular serves as a redundant or backup seal for both the pipe and the blind rams and can also be used in a deployment system. Tool String Deployment System The tool string deployment system allows long coiled tubing strings to be deployed into a live well with out requiring an injector rig-up on top of a long injector/riser configuration. The technique uses a wireline system to temporarily position the tool string inside the wellhead where it is remotely latched on coiled tubing and run in the well, an Annular BOP can be incorporated in the configuration to aid deployment.
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Quick Union and Flanges
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Bottom Hole Assemblies A key element of most coiled tubing jobs is the type of tool or combination of tools that are needed to bring about a desired result. Many categories of tools exist; the common ones are covered in this overview. Each tool category contains various types of tools, but only the most used will be described here. Tool functionality and BHA tool string design will be discussed, but this is an overview and not intended to be used instead of Standards & Practices. For specifications and information regarding sizes, material strengths and pressure limits, etc. consult the appropriate tool manual. The tools covered have been categorized as follows: • Connectors • Valves • Disconnects • Locators • Centralizers & Stabilizers • Wash Tools • Downhole Separator • Impact Tools • Shifting Tools • Stiff Wireline Tools • Fishing Tools • Specialty Tools
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Tubing End Connectors Tubing End Connectors (TEC) are used to attach tools or tool strings to the end of the coiled tubing. There are many types and variations and there are operating guidelines for which connector to use for a specific operation. The size of the coiled tubing is also a factor, as some connectors cannot be used with certain coiled tubing sizes. The connectors discussed here are the ones most commonly used and include the roll-on, external grapple and DimpleonTM. Roll-on The roll-on connector, fitted with threads on one end, is used to connect the coiled tubing end to a tool or tool string. A double roll-on can be used to splice two coiled tubing strings together (in emergency situations) or to retrieve a hanging string. This connector is used primarily with smaller tool strings and jobs not involving torsion. Installation A roller is used to press the walls of the coiled tubing into groves that are machined into the roll-on. O-rings are used to prevent leaks so the coiled tubing weld seam has to be removed prior to installation to prevent damage to the Orings. The correct roller size and profile are necessary for correct installation. Over-rolling the coiled tubing, when installing the roll-on connector can significantly reduce the coiled tubing yield strength at the connection. Operational Details • There is a correct roll-on fitting size for each size and thickness of coiled tubing. • Roll-ons with sharp shoulders give variable performance. BJ roll-ons have rounded shoulders. • Any thread type can be used. • The roll-on connector is an inline connector, so it does not normally increase the OD of the coiled tubing but it does decrease the CT inside diameter. • This type of connector is not robust enough to be used in some kinds of operations such as drilling, percussion or work that involves jarring, vibration and torsion or high axial load operations.
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Figure 19 Roll On Connectors
Figure 20 Roll-on Connector
External Grapple The external grapple is a robust connector that is recommended for milling, fishing and heavy duty coiled tubing operations. There are various models and designs but the BJ model gives the best performance. It consists of a grapple that bites into the coiled tubing. The number of slots in the grapple varies between manufacturers and has a major effect on performance. The grapple bites harder as the pull on the coiled tubing increases (unless not installed properly). A stepped design allows the grapple to bite all along its length. The tubing should be cleaned prior to installation to ensure the O-rings seal properly. Several pull tests, using a C-plate, are normally needed to get a proper bite into the coiled tubing. EDC – Tomball, Version 1.01 Revised: April 2005
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Designs that use set screws are inferior, as only one set screw tends to hold the applied torque. The BJ and BDK models do not use set screws. Operational Details • Since this tool increases the OD of the coiled tubing, it cannot be run through the injector and stuffing box. • Used for all sizes of coiled tubing although not common for 1-1/4” (31.8 mm) and 3-1/2” (88.9 mm). • The grapple should be replaced after each job. • Grapple surfaces are hardened to enable them to bite.
Figure 21 External Grapple Connector
Dimpleon™ This connector is an internal TEC and accordingly is flush with coiled tubing OD; note that it will therefore decrease the available through Id. The Dimpleon connector is considered secondary compared to the BJ Grapple, as field studies have shown, prolonged exposure to a H2S environment can cause the coiled tubing to crack in the dimple depressions. The connector slides inside the coiled tubing. The coiled tubing is dimpled into the connector using a bushing and hydraulic press arrangement. The internal weld bead is removed using reamers. Note: Special fitting tools are required and the connector is CT wall-thickness specific.
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Operational Details • Used for all sizes of coiled tubing. • Has larger through bores than conventional roll-ons. • Strong in tension and torsion. • Fitting is easier and more consistent than for roll-on or grapple connectors. • The connection is more resistant to H2S than the dimple or grapple connection. • The connector can be reused.
Figure 22 Dimpleon™ Connector
Figure 23 Dimpleon™ Tools
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Valves Valves are an important part of a coiled tubing tool string and there are very few applications in which some type of valve would not be. The primary types that are discussed here include check valve, sequence valve and dual activated circulation sub. Check Valves A check valve is required on all jobs, except reverse circulating operations. Check valves are installed as a precaution against back flow up the coiled tubing to surface. The two main types of check valves are the double dart and double flapper type. Dart A “double dart” configuration should be run on simple jobs with slick tool strings. It cannot be used with a hydraulic release tool since its configuration will not allow the passage of a ball.
Figure 24 Dart Check Valve
Figure 25 Double Flapper Check Valve
Double Flapper The double flapper check valve is the favored valve for most operations since it has a full bore ID that can accommodate passage of a ball to activate a hydraulic release tool or other tools. It contains two cartridges each with a flapper and spring that provide a positive seal. It seals well at low and high pressures. Operational Details • Both cartridges should be individually pressure tested at high and low pressures.
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• The cartridges should always be staggered by some angle but not completely opposite to each other. This can prevent a ball from seating between them in high angle wells. • Always placed above the disconnect tool in the tool string. This prevents flow up the coiled tubing when the tool string is disconnected. Sequence A sequence valve is a valuable tool that is generally under utilized. Typical operations where the tool is used are cementing, setting inflatable packers, drilling and any situation where coiled tubing collapse is a possibility. Coiled tubing collapse scenarios occur in high-pressure gas wells. The most common use of a sequence valve is to provide hydrostatic pressure control in low-pressure wells, or when a high-density fluid like cement is used. Pressure settings can vary with a spring and piston mechanism. Flow through a sequence valve will only occur when the pressure at the tool is greater than the combined pressure of the tool setting and the pressure outside the tool. For example, if the tool is set to 2000 psi and the bottom hole pressure is 2000 psi, then a pressure of 4001 psi would be needed inside the tool to allow flow. Operational Details • Some sequence valves are suitable for abrasive fluids, such as cement; while others have to be dressed with tungsten carbide inserts to prevent erosion. • Sequence valves can be stacked in the tool string to provide a higher overall differential opening pressure.
Figure 26 Sequence Valve
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Dual Actuated Circulation Sub The main function of this tool is to divert flow and bypass the remainder of the tool string. This is often used after milling when the mud motor is bypassed to reduce wear on the motor and prevent scarring on the tubing during pull out. It also permits higher flow rates to improve hole cleaning. The tool is dual activated such that a ball is pumped from surface which shuts off flow. Pressure buildup causes shear pins to shear and shift a piston to open circulation ports. Rupture discs are situated below the ball seat. If the tool string was plugged so that a ball could not be pumped, then pressure could be applied to rupture the disc. This results in a flow path so that a ball can be circulated down to the circulation sub or to a disconnect tool. Operational Details • Placed below the hydraulic disconnect and above the mud motor in milling jobs or remaining tool string. • Has large ID for high flow rates.
Figure 27 Dual Actuated Circulation Sub (Dump Sub)
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Disconnects Some method of disconnect is needed on most coiled tubing jobs since the bottom hole assemblies (BHA) are typically larger than the coiled tubing OD’s, thus potentially making them susceptible to becoming stuck. However, disconnect tools may not be needed if the BHA OD is the same size as the coiled tubing (slick). Examples of types of jobs using a slick BHA would be gas lifting or unloading fluid from a well. For stiff wireline jobs the tool of choice is the Bakke flow release cable head tool. An advantage of this tool is that both flow and tensile load are required to execute the release mechanism. This means that in the normal mode of operation, the shear pins are not subjected to an external load and unintentional release is minimized. Other tools include a shear release tool, which relies solely on shear pins and a tension release tool that uses a spring loaded collet instead of shear pins. The disadvantage of these tools lies in the fact that the shear pins or spring have to be set high enough to avoid accidental activation while still allowing release in all circumstances. This can be difficult in deviated or horizontal wells. Bakke Hydraulic Release The hydraulic release tool is the tool of choice on all jobs not using an electric line in the coiled tubing. The tools on the market have been internally tested (CTRE) and the Bakke tool has been recommended as the best of all. These tools are able to withstand high tensile, torsion and shock forces and can be used for fishing and milling jobs. The ball is circulated down the ct and enters the tool and is caught in a ball catcher, which is situated in a shear pin piston. The ball prevents further flow through the piston and the resulting differential pressure will build until shear pins are sheared. The number of shear pins determines the value of the differential pressure. Once the shear pins have been sheared, the piston moves down to release the dogs holding the tool together. The coil then has to be picked up to separate from the lower connector. Operational Details In order for the tool to work a ball has to be circulated down through the coiled tubing string. For this reason the coiled tubing reel should contain a ball launcher or a method of launching a ball. There are required minimum flow rates for each size ball and coiled tubing diameter in order to circulate the ball EDC – Tomball, Version 1.01 Revised: April 2005
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around the reel and over the gooseneck. Once the ball is in the vertical section, pumping should be discontinued and the ball allowed to freefall. This is to avoid a water hammer effect when the ball seats in the tool. If the tool was situated a considerable distance into a horizontal section, the ball may have to be pumped in order to reach the BHA. • The smallest hydraulic disconnect size is 1.75” (44.5 mm) which is suitable for many jobs involving 1.25” (31.8 mm) or 1.5 (38.1 mm) coiled tubing. For larger coiled tubing sizes a larger hydraulic disconnect would be used. • The Bakke disconnect leaves internal and external fishnecks. • Normally placed below check valves in the tool string. It can be run below jars and accelerators.
Figure 28 Bakke Hydraulic Release Tool
Motor Head Assemblies (MHA) Coiled tubing motor head assemblies have been developed to provide a compact, versatile upper BHA component that combines the double flapper check valve, hydraulic disconnect and a dual circulation sub all in one tool. The tubing end connector is not incorporated in the tool, thus allowing for flexibility in connector selection.
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Locators Locators are used as part of the coiled tubing tool string to locate nipples in production tubing, the tubing end, crossovers or sliding sleeve profiles. The locators are used so the BHA depth can be determined precisely and the coiled tubing depth counter corrected. The easiest and most common method to determine BHA location is by locating on a profile or the end of the production tubing. In many jobs accuracy in depth measurement is necessary i.e. jetting acid across a small set of perforations in a deep well. Generally, the section of the well to be treated will be close to the end of the production tubing. After correlating to the production tubing-end the additional error in reaching the perforations is typically negligible. Many times it is not possible to tag TD of the well and calibrate the depth counter as the well may be full of debris in the rat hole and therefore TD is uncertain. Mechanical Depth Counters (odometers) are reasonably accurate although even an accurate one (i.e. +/- 0.1 %) gives significant errors in deep wells. Odometers can be affected by debris or coating on the odometer wheel; fast running speeds may cause the odometer wheel to skip and introduce error. Stretch and temperature effects change the depth of the tool string. Large completions also have an effect as the coil tends to helix or corkscrew. Tubing End Locator This type of tool should not be run with expensive BHA’s such as perforation guns as they have been known to cause problems, Instead, a depth correlation run should be made first and the coiled tubing flagged for reference. The tubing end locator that is typically used is a one-shot locator. A spring arm remains collapsed as it is run through tubing, but opens after passing through the bottom of the tubing. As the arm is pulled back into the tubing a weight gain will be seen on surface to indicate the end of the tubing and a shear pin in the tool will be broken to release the arm. An aluminum hinge pin is sometimes used to hold the arm and it can be broken if the arm doesn’t fold back properly. Operational Details • The shear pin should always be changed before running in hole and it should be checked to ensure it fits snugly. • Pull tests should be done carefully to prevent damage to the arm. • Debris can collect in the location of the arm and hinge to prevent the arm from folding back properly. EDC – Tomball, Version 1.01 Revised: April 2005
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• This tool should always be run below the disconnect tool.
Figure 29 Tail Pipe Locator
Nipple Locator This tool can be used to locate most tubing nipple profiles. Normally, three profiled arms, attached to leaf springs, are used to locate the nipples. The arms are sized larger than the minimum nipple ID. The arms are also profiled or contoured so that they pass through the nipple easily but require an overpull to pull back through it. The leaf spring can be adjusted with a screw to increase or decrease the amount of overpull. Operational Details • The profile arms need to be gauged with a gauge ring. The tool should drop through on its own weight. A load cell should be used to measure the amount of pull required to pull the tool back through the gauge ring. • Leaf springs lose strength if they are used for a long time. • Not a good idea to use this tool as a tubing end locator as there may be considerable drag while running in hole. A slightly smaller ID in the tubing could cause a problem because there may be insufficient overpull available to retrieve the tool string.
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Centralizers & Stabilizers Centralizers are used to center a tool string in tubing or casing. Without any centralization, the tool string would tend to lie on the wall of the tubing, casing or open hole. This can make passage through restrictions such as landing nipples and side pocket mandrels difficult. Residual curvature in the coiled tubing is a contributing factor to this condition. Centralizers are used to provide standoff in perforating and jetting operations. Stabilizers are often used to stabilize and centralize tool strings. They are used for milling, drilling and fishing operations. Centralizers and stabilizers can be fixed or hydraulically operated. Hydraulically operated types are more commonly used with coiled tubing. Fluted Stabilizer The fluted stabilizer uses fins that have shaped or rounded shoulders to provide centralization and stabilization. Fixed stabilizers are normally used when there is no downhole restriction. Non-rotating stabilizers are more common and they reduce whirling generated from rotating equipment. Operational Details • The minimum number of fins to give reasonably good centralization is five. More fins than five or six could create a flow restriction problem. • Typically run below the disconnect tool and above the motor in milling jobs. • Often used in pairs to provide added stability in drilling operations.
Figure 30 Fluted Stabilizer
Bow Spring A collapsible centralizer designed for slick tool strings. Some models fit over the tools or coiled tubing. Bow springs collapse in the restriction and expand to EDC – Tomball, Version 1.01 Revised: April 2005
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full OD once past the restriction. Should not be used with coiled tubing due to numerous problems, such as, trapped debris in spring arm and spring arms failing in the well. Operational Details • Needs to be robust. • Disadvantage is that there can be a significant amount of wear when running through the completion. • Long, thin bow springs do not centralize well. • It is possible to become stuck when pulling back into the production tubing.
Figure 31 Bow Spring Centralizer
Hydraulic Bow Spring / Stabilizer This tool is designed for use with coiled tubing as it can be run through small ID tubing and then activated in large ID casing. The bow springs are shorter, thicker and stronger than conventional mechanical bow springs. It is run through tubing and restrictions in a retracted position. Pumping through an orifice creates a pressure drop and causes a piston to open the springs. Larger orifice sizes can be used to allow more flow through the tool without activation. Operational Details • Capable of large expansion with a small retracted diameter. • Expansion of the springs can be adjusted. • The bulk of the load is usually at the base of the bow springs, so these areas should be checked for cracks. • Typically run below a hydraulic disconnect tool and a dual actuated circulating sub.
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Knuckle Joint Knuckle joints are used in long tool strings to provide flexibility. This may be useful in maneuvering through tight bends in deviated and horizontal wells. Sometimes they are used in conjunction with a hydraulic centralizer in fishing operations as they reduce the weight that the centralizer has to support. Problems have been associated with their use. Some designs have flat shoulders that can hang up on restrictions. They are usually the weak link in the tool string. Pump pressure can reduce the bending that does occur. Two knuckle joints can be used but are not recommended. Lock up can occur when two knuckle joints are used. Operational Details • The knuckle joint will pivot to maximum of 11 degrees. • Single and dual types are available. • In fishing operations they are positioned above a centralizer.
Figure 32 Knuckle Joint
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Wash Tools The type of wash tool used depends on the application. Applications range from simple fluid displacement, to filter cake removal, to difficult scale removal. Lift assistance may be necessary with the use of nitrogen. Other fluids that may be pumped include gelled water, foam or acid. Completion size and type will affect the choice of nozzle although a variety of sizes are available for each tool. Cleanout Nozzles These types of nozzles include straight jet, jet down, jet up and tangential. The choice of nozzle orientation is chosen based on the type of job. Most often they are used for gas lifting, sand cleanouts and spotting fluids such as acid and cement. These jets are not effective for removing filter cake or scales. The nozzles usually have 5 ports and forward jetting is often optional. The straight jet nozzle has a single forward jetting nozzle that allows a high flow rate with low backpressure. This nozzle is used when it is necessary to circulate fluids at high rates such as cement or when ‘bullheading’. Jet down nozzles are used to jet fluid on the wellbore sides. Normally have 5 ports, four sets at 30-degree angles from the tool centerline and one forward to penetrate fill (optional). This nozzle may be used for acid washes. Tangential jets are used to maximize jetting contact with the completion as the jets exit the tool tangentially. Tangential jets provide good mixing of the fluids in the wellbore. These are also used for acid washes and cement placement. Vortex Nozzle The Vortex nozzle generates a vortex or fast swirling mass of fluid in the completion tubular or open hole. Rotational speeds of the vortex can exceed 8,000 rpm. The vortex entrains debris, which improves hole cleaning. The Vortex nozzle is normally used for cleaning wax from tubulars, washing perforations or washing mud filter cake from open-hole well bores. It is effective against some scales. The tool uses 4 tangentially offset nozzles. The nozzles are more efficient than conventional designs because specially designed flow guides ‘pre-swirl’ the fluid and jet orifice geometry has been optimized.
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Operational Details • The tool is available in a number of sizes {1-3/4” (44.5 mm), 2-1/8” (54 mm) and 2-7/8” (73 mm)} with 3 jet orifice sizes (A, B, or C). • A downhole magnetic filter should always be used with the Vortex nozzle. • The Vortex nozzle is placed below check valves and hydraulic disconnect tool in the tool string.
Figure 33 Vortex Nozzle
Figure 34 Cut-away of Vortex Nozzle
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Roto-Jet™ The Roto-Jet™ tool delivers a powerful jetting stream that can be used to remove hard scales, waxes, filtercake and tar. The nozzles rotate at controlled speeds to create stress cycling in the scale or filter cake. The components of the Roto-Jet™ consist of a downhole filter, a governor section, a turbine section, upper and lower bearing sections, and a jetting mole. The turbine section consists of stator and rotor stages. Momentum transfer from the pumped fluid causes the rotor shaft to turn. The governor section consists of rare earth magnets attached to the drive shaft and housed in a copper tube. The rotating magnets induce an electric field. Eddy currents are created in the copper tube, which resist rotation and prevent over speeding of the shaft. The jetting mole is connected to the bottom of the turbine shaft and has two jet nozzles. Careful design of the internal flow geometry and orifice geometry has made these nozzles extremely efficient. Two different nozzle sizes are available for the Roto-Jet™ tool. One is directed down at 45 degrees (R45) to the tool axis and the other is at 90 (R90) degrees or perpendicular to the tool axis. The number of magnets may be varied to give the required rotational speed for a given flowrate. Operational Details • Each tool size has minimum and maximum flow rates. • An option is available to put all the flow through the turbine or divert a portion through the turbine shaft. • All types of fluids or nitrified fluid can be pumped through the tool except toluene. • Nitrogen does reduce the coherence and effectiveness of the jet stream. The downhole separator should be considered for use with the Roto-Jet™ tool when nitrogen is necessary. • The tool generates only 8-12 ft-lbs (10.8 – 16.3 N*m) of torque, therefore cannot be used in a ‘drilling’ mode. • The Roto-Jet™ tool is run below check valves and a hydraulic disconnect tool. • A surface and downhole filter are required when running the Roto-Jet™ tool. • A downhole magnetic filter must always be run.
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Figure 35 Roto-Jet ™ Tool
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Venturi Junk Basket The Venturi junk basket is used to clean large debris from vertical and horizontal wells, i.e. debris that cannot be removed conventially because sufficient velocities are not possible. The tool uses a venturi effect. Fluid or gas is pumped through one or two small nozzles which creates a pressure drop within the tool. The fluid exiting the nozzle(s) passes into the wellbore and helps to stir up debris at the front of the tool. Fluid and debris are drawn into the tool and trapped between a screen and a trap door. Operational Details • Only a small pressure differential is necessary to fill the basket. • Extensions on the tool of 100 ft or more can be used. • Can be run under a motor to pick up debris from a milling operation.
Figure 36 Venturi Junk Basket
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Downhole Gas Separator The downhole gas separator is used to separate gas from fluid above a jetting tool or motor. This is useful since nitrogen is often needed to maintain an underbalanced condition in the wellbore but detracts from the performance of the tool. The Roto-Jet™ tool is the best example of this. Another example is when the maximum rate allowed through the BHA, such as a motor, is exceeded. A centrifugal action is created within the tool, which separates most of the gas from the fluid. The gas is dumped into the wellbore while the liquid continues out the bottom of the tool. The pressure drop in the tool is small and less than 2% of the gas is carried through with the liquid. The best performance from the tool is maintained when the gas ratio is between 25% and 75%. Operational Details • Tool sizes that are available are 1-3/4” (44.5 mm), 2-1/8” (54 mm) and 2-7/8” (73 mm). • There are maximum combined flow rates for each size.
Figure 37 Downhole Gas Separator
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Impact Tools Impact tools are used to provide mechanical force to objects. They are used extensively in fishing operations, pulling plugs and for special operations such as opening sliding sleeves. These tools include impact hammers, jars, accelerators and shock subs. They can be used in vertical and horizontal wells. Important Note: A shear pin release tool cannot be used with impact tools. The coiled tubing, coiled tubing connector and release tool have to be properly sized for the size of impact tool being used. Impact Hammers Also known as a “hydraulic percussion drill”. This tool acts like a jackhammer to provide downward jarring force. They are typically used for opening sliding sleeves, pulling plugs or for fishing operations. The quick repetitive blows are useful for jarring/vibrating plugs free. Generally, hammers are more effective than jars for generating downward force. Dual acting impact hammers are also available that will provide upward impact as well as downward impact. When the tool is not tagging anything, circulation is through the tool. As soon as the tool tags and weight is applied, circulation stops and the pressure inside builds causing the tool to stroke back until circulation ports open, then the tool drops with considerable force back into the closed position. The stroke is small and the frequency of impact varies according to the flow rate and set down weight. Higher flowrates result in increased impact frequency but not harder impacts. Pull up weight is necessary to activate an upward force for bidirectional hammers. The tool operates with water, acid or nitrogen. Acid should be inhibited. Operational Details • Shock subs or accelerators should always be used with impact hammers. • Sizes vary from 1-1/16” (43 mm) to 6-1/4” (158.8 mm). • A Double flapper check valve and heavy duty hydraulic release tool should be used. • A fit for purpose bit may be used on the end of the hammer, depending on the type of operation.
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Jars There are two types of jars, mechanical and hydraulic, and they are used to provide a powerful upward impact. The hydraulic design is more effective and normally used. Bi-directional jars that fire downward as well as upward, are available. The design of jars and accelerators for a specific application is difficult so it is very important that the services of a qualified and experienced jar company be employed. The hydraulic jar is cocked or loaded by pulling up on the coiled tubing. This causes a piston to move in the jar, which transfers oil in a chamber from the top to the bottom. The piston pulls slowly in a restricted area but accelerates once it clears the restricted area to provide impact energy. The amount of overpull with hydraulic jars does not affect impact energy as it does with mechanical jars. A bypass port allows the jar to be reset quickly. Bi-directional jars require set down weight to fire downward. Operational Details • Accelerators are always used with jars and they have to be compatible. A weight bar is normally placed between the jar and accelerator to increase the impact energy. • Bi-directional jars may not be suitable with coiled tubing in all cases since enough set down weight may not be available to impact downward with sufficient force. An impact hammer may be a better choice for applications needing downward force. • A jar stroke length is about 6 inches. The stroke length of accelerator is usually 7-8 inches (177.8 – 203.2 mm) and it must exceed the jar stroke length to be effective. • Oil used in jars is chosen based on bottom hole temperature and available overpull. The oil heats during jarring and needs time to cool. • Disconnect below the jars if possible (disconnect ball must be able to pass through jar. Accelerator Accelerators are used to accelerate or intensify impacts during jarring operations and also protect the coil tubing and tool string from damaging shock waves. Mechanical and hydraulic types are available although the hydraulic design is normally used.
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The accelerator is either oil or gas filled and it acts like a spring. The stroke of the jar releases the energy stored in the accelerator. The accelerator provides the greater part of the total energy released by the jar/accelerator combination. Operational Details • Positioned above weight bars and jars. • Disconnect below accelerator and jars if possible (disconnect ball must be able to pass through jars and accelerator). Shock Sub A shock sub is used to cushion the blow from impact hammers and protect the coiled tubing and coiled tubing tool string. They use disk or beveled springs that compress and release. Operational Details • Disconnect below accelerator, jars and shock sub if possible (disconnect ball must be able to pass through jars, accelerator and shock sub). Shifting Tools Shifting tools are used to open and close sliding sleeves. These can be in vertical or horizontal wells. Examples of the tools that are commonly employed for this service are the Baker HB-3 and Power Stroker. HB-3 Designed to work on Baker HL and CM type sliding sleeves. The tool is dressed to shift either up or down. Circulation is through the tool while RIH. An increase in pump pressure activates the tool by compressing a spring, which allows a second spring to extend a set of linkage arms radial. These arms latch into the sleeve insert. The sleeve can be shifted up or down by pulling up, setting weight or by using an impact tool. Once the sleeve is shifted, the shifting tool releases. Decreasing the pump pressure causes the linkage arms to retract so they should not contact the completion tubulars. Operational Details • Activation pressure is low. • Depth control is necessary. EDC – Tomball, Version 1.01 Revised: April 2005
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Power Stroker This tool can be used in conjunction with the HB-3 shifting tool. It anchors in a tubing profile after the HB-3 has located the sleeve. Pump pressure in the tool gives a downward force to assist the HB-3 in shifting the sleeve. It can be run between HB-3 shifting tools to enable sleeves to be opened and closed with one run. It has an emergency shear release.
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Stiff Wireline Tools These are used to connect tools requiring an electric line to coiled tubing. Used primarily in logging and perforating operations, and also for electrical-setting packers. The Bakke flow release cable head tool has replaced the stiffwireline connector and tension release tool in most operating locations. Bakke Flow Release Cable Head Tool The Bakke flow release cable head tool is used for stiff wireline jobs involving perforating, logging and setting plugs. The tool is designed to withstand shock from heavy perforating guns and can carry heavy loads. It contains an anchor for a stiffwireline cable, double flapper check valves and a hydraulic release mechanism. To activate release, fluid is pumped through nozzles to create a pressure drop. The pressure drop is transmitted through a tube to a spring-loaded piston. The movement of the piston causes mechanical slips to release. The tool’s release can then be accomplished by applying a tensile pull to shear pins. The number of shear pins and nozzle sizes can be adjusted to suit job conditions. Operational Details • The shear pins do not see any load during normal operations. • Tool is set up so as to ensure its possible to achieve pressures 20% higher than the required release pressure. • When pressure testing in the riser the pressure has to be bled off slowly so that the tool does not experience a higher pressure drop than its set value.
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Fishing Tools Items that fishing tools may be used to retrieve include broken or stuck tools, packers and plugs, coiled tubing and junk in a well. There are many methods and types of fishing tools but the most common types used with coiled tubing can be grouped as spears and overshots. Hydraulic releasing spears and overshots have been designed specifically for coiled tubing and they are a much better choice than conventional wireline type fishing tools. Generally, specific fishing tools are used for specific tasks. Sometimes a fish has to be dressed by first latching on with a spear or overshot and then activating the hydraulic release tool to leave behind a standard fishing neck. Or a motor and mill may be used to dress the fish and make it retrievable. It is very important that information about the fish be known, such as internal and external dimensions, length and material hardness. This type of information should be documented for each tool in the tool string before it is run into the hole. Fishing tools are commonly run with jars and accelerators or impact hammers. Normally, two hydraulic disconnects should be run when jars and accelerators are used for fishing. One would be placed above and the other below the jar/accelerator combination. If only one hydraulic disconnect is available, it should be run below the jars. Jars should never be left behind because they are very difficult to fish. Other coiled tubing tools that may be used to assist in removing an object include motors, bits, centralizers, knuckle joints, indexing tools and bent subs. Spears Spears are used to engage internal fishnecks that may be either a standard size or slick. Hydraulic spears are typically used with coiled tubing. A spear, such as an ITCO type, is not good for CT fishing because it can not be backed off but it may be used to bait a fish. In this case it would be run with a disconnect tool that has a standard GS fishneck. A GS hydraulic releasing spear is used to fish a GS internal fishneck. Hydraulic Releasing Spear These tools can be pumped through. A hydraulic releasing fishing neck spear uses collets to latch into the profile of the fishneck. A slick ID hydraulic releasing spear uses grapples or slips to catch the slick ID fishneck.
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In either case, the spear is run as far as possible into the fish. A small set down weight releases the collets or slips, enabling them to latch on to the fish. An increase in flowrate detaches the collets or slips from the fish. The material of the slips has to be harder than the fish in order to grab into it. The collets may also be hardened.
Figure 38 Hydraulic Releasing Spear
Fishing Overshots The overshot is a versatile and efficient fishing tool that is widely used. There are many different types but common ones are listed below. They will latch on to standard fishnecks or slick OD objects. Some overshots are designed to swallow coiled tubing and cut coiled tubing. Various types of shoes and guides can be used to help to locate the fish. These tools are designed to withstand stresses that result from jarring. Flow through the tool washes debris from the top of the fish. Hydraulic Releasing Overshot This tool can be used for fishing a slick OD fish or grabbing a standard fishing neck. An overshot with collets is used to latch a standard fishing neck while grapples are used to engage a slick OD fish. A small set down weight releases the collets or grapples allowing them to engage the fish. The fish can then be pulled or jarring initiated. If the fish will EDC – Tomball, Version 1.01 Revised: April 2005
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not release, the pump rate can be increased to disengage the collets or grapples. Jarring down may be necessary to break the grip from the grapples. The material of the grapples has to be harder than the fish in order to bite.
Figure 39 Hydraulic Releasing Overshot
Bowen Fishing Overshots The overshot can be dressed with either a spiral grapple or a basket grapple. The spiral grapple is used when the diameter of the fish is close to the maximum catch diameter of the overshot. The basket grapple is used if the fish is considerably less (1/2”) than the maximum catch size. As the tool is lowered and engages the fish, the grapple expands allowing the fish to enter it. Then, with an upward pull, the grapple contacts the fish and the wickers bite into it. Operational Details • Extra length may be put on the front to swallow more of the fish. • A cut lip guide on the end of the overshot with a kick off tool, indexing tool or motor may be used to assist in locating a fish. A hollow mill may be run on the end to mill on to the fish. • A mill control packer may be used with a basket grapple to lightly dress the fish before it is engaged although it is not normally used with coiled tubing.
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Figure 40 Bowen Overshot
Continuous Coiled Tubing Overshot This tool is used when the fish is coiled tubing. It may be run with an extension as it is advantageous to grab the coil as far down as possible. Once the overshot is over the coiled tubing it will engage when the tool is raised. The grapple does not put a high compressive load on the coiled tubing. Operational Details • A cutlip guide or mill guide may be used below the overshot to help locate and bait the fish. Once the overshot is latched on a shear disconnect would be sheared leaving the baited fish. Kick-Off Tool The kick-off tool is a reliable and versatile tool that is used to assist the BHA in getting past obstacles or restrictions such as landing nipples, gas lift mandrels and liner laps. To be effective, it has to be used with a kick-off (or mule shoe) nozzle or shoe. When an obstruction is tagged, the tool compresses and an internal key slot causes it to rotate. A beveled shoe or nozzle on the end of the string deflects the EDC – Tomball, Version 1.01 Revised: April 2005
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tool and enables it to clear the obstruction. The tool then resets to its normal position.
Figure 41 Kick-Off Tool
Indexing Tool An indexing tool is used to rotate the BHA through a fixed angle. This can be used for getting past an obstacle, orienting an overshot onto a fish or possibly entering different legs in multi-lateral wells. When an object is tagged the applied force or pressure moves a spring loaded Jslot, which rotates the tool. When the pressure is released, the indexing pin acquires a new position in the J-slot. This process can be continued until a successful orientation is found. Another version of this tool works on pressure drop caused by flow. Operational Details • Rotating angles usually 15 or 30 degrees. • Tool often used with bent sub or centralizer in larger ID’s. • Tools that work with set down weight could be a problem since the pin in the J-slot has to handle the entire load (and it won’t take a big load). • A kick off tool may be a better alternative in some instances. Straight Bar / Weight Bar A straight bar is used to assist a tool string to pass through restrictions or obstructions by providing a straight section below the coiled tubing. The coiled tubing normally retains some residual curvature which can affect a tools ability to pass a restriction. EDC – Tomball, Version 1.01 Revised: April 2005
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Because straight bars are thicker walled they cannot be sheared with the BOP rams and they should not be confused with deployment bars which are meant for locating the tool string in the BOP's and which can be sheared with the shear rams. Impression Block This is a pump through tool with a lead block that is used in fishing operations. The impression left on the block after tagging a fish may assist the operators in devising a strategy for recovering the fish. Wire Rope Spear & Stop This tool is used for fishing wireline. Barbs on the spear help to grab and hold the wireline. A stopper on the top of the tool prevents wire from bypassing the tool. It is often run with a motor so the tool can be rotated. Over rotation should be avoided, as a large wire bundle on the spear may be difficult to pull from the hole with the coiled tubing. A hydraulic disconnect is run above the tool.
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Specialty Tools Parabow The parabow tool was designed for cement plug applications utilizing drill pipe and has been adapted for use with coiled tubing. It is an inexpensive but effective method of providing a stable base for cement plugs, thereby eliminating gravity segregation or ‘density slumping’ from occurring. Activation of the tool is initiated by circulating a ball; this shifts the circulation ports and allows the parabow to extrude from the tool and expand across the wellbore. There has to be fluid below to prevent the parabow from slipping downhole.
Figue 42 Parabow Tool
Sand-Vac / Well-Vac This tool consists of a modified jet pump and it is run on concentric coiled tubing. It can operate in cleaning or production modes and is used primarily for removing sand and drilling fluids from heavy oil horizontal wells. In cleaning mode, external jets are used to fluidize sand and debris ahead of and behind the tool. In production mode the external jets are shut off to maximize production from the well. A lowering of the pump rate causes the tool to shift from one mode to the other. Typically, the tool is run in hole in cleaning mode and pulled out of hole in production mode. Fluid is pumped through the inside string while returns are up the annulus of the two strings. The primary components of a jet pump are a power nozzle and throat and it works by energy conversion. High pressure passes through the nozzle where it is converted to a high velocity and low pressure stream. This induces flow from the well. The combined flow passes into a throat and EDC – Tomball, Version 1.01 Revised: April 2005
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diffuser where velocity is slowed and pressure increased high enough to overcome hydrostatic pressure. The current concentric coiled tubing string configuration is 1-1/4” (31.8 mm) in 2-3/8” (60.3 mm). The tool OD is 3-3/4”. Different sizes of power nozzles and throats are available.
Figure 43 Sand-Vac / Well-Vac Tool
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Tornado BJ Services specifically developed its Tornado coiled tubing wash tool as part of an improved process for well clean-out operations. Used in conjunction with BJ’s Tornado job design software, CTran, this revolutionary process provides a highly effective means for removing sand and familiar material from deviated or horizontal wellbores. The Tornado nozzle diverts the flow of jetting fluid in either direction; forward facing jets to break-up compacted fill while running in the hole and then cycle to the backward facing jets to efficiently sweep fill from the low side of the well while pulling out of hole –wiper trip. Ctran software calculates how fast the coiled tubing can be run into the fill and how quickly the coiled tubing can be pulled out of hole in reverse cleaning mode. The tool is the market leader in fill removal and with Ctran pre-job modeling, effective fill removal is assured – virtually 100%.
Figure 44 Tornado Tool Process, as Simulated by CTran
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Straddle Packer The 3” (76.2 mm) straddle packer tool is used to isolate perforated zones or open hole to allow placement of stimulation fluids. It can be reset up to 20 times for multi-zone treatment. It will seal in as large as 6-1/4” (158.8 mm) hole. Circulating at a pre-set flowrate activates it; a valve mechanism prevents over-inflation of the packer elements. Pulling up the coiled tubing causes the packer elements to deflate and the tool to reset – time must be allowed for the element to deflate fully prior to moving the tool in the wellbore, thus preventing element damage. The packer elements are rated to a temperature of 284 °F (140 °C).
Figure 45 BJ Straddle Packer (showing 1 packer element)
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Coiled Tubing Manufacturing The text in this section has been extracted from the Quality Tubing, Inc. web site.
Manufactured coiled tubing strings are designed to specified-length strings of high quality materials, suitable for field operations. In order to produce long lengths of pipe, QTI welds steel strips together, and produces pipe from the strip by the high frequency induction (HFI) electric welding process. This section of the Technical Catalog describes how QTI's pipe is produced from steel strip, and the testing procedures to which both the strip and pipe are subjected before release to the customer. Early Designs The original idea for coiled tubing came from the project "Pipe Line Under the Ocean" (PLUTO) where range II line pipe was butt-welded, rolled onto spools, and laid from boats under the English Channel in 1944 to support the Normandy landings. Coiled tubing continued to be produced by butt-welding on a relatively small scale into the 1960s. The weak link in this form of continuous pipe is the butt-weld; it causes structural weakness and restricts internal flow. A high percentage of the failures that occur over the life of butt-welded pipe are, breaks that occur in the heat affected zone adjacent to the weld bead. The material in this area fatigues much more rapidly than the parent material, especially in a sour gas environment. The internal circumferential weld bead, which is not generally uniform due to the effects of gravity, restricts fluid flow and causes turbulence. It also restricts operations that require pumping tools or steel balls through the tube.
Figure 46 – Butt Weld
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The Quality Difference Because of the deficiencies of the butt weld, QTI introduced two new ideas. First, a patented strip bias weld process for joining two strips before the tube is manufactured was introduced. Second, by purchasing premium class coils in strip form, QTI was able to drastically reduce the number of welds in a string of tubing. Thus in some sizes of material, the welds may be over 1000 m (3280 ft) apart. These developments eliminated the weak links and dramatically improved the reliability of coiled tubing in the field. Starting From Flat Strip QTI purchases hot rolled coils of flat strip from major approved suppliers. Coils are rolled to specific sizes and tolerances. Each coil is then split into the required strip widths for pipe production, again to specific tolerances. In the case of QTI's TRUE-TAPER product, the strip will be thicker at one end than at the other. QTI can then join strips of equal thickness thickness at each end reducing the stress concentrations caused by non-uniform load transfer when joining differing gauge material. Patented Strip, Bias Weld Process In 1989, QTI patented a strip welding process that is shown schematically in Figure 1-3 (US patent 4 863 091). The edges of strip to be welded are carefully prepared by shearing at a fixed angle, and then welded by computer-aided welding machines. This strip weld is stress relieved and inspected nondestructively by visual and x-radiographic processes. Customers may also specify magnetic particle inspection. The x-radiographic process, which is performed either with high speed film or a digital real-time X-ray device, is controlled ultimately by an ASTM penetrameter and meets or exceeds the requirements of ASME Section V and API 1104. Due to the sensitivity of the inspection technique, no imperfections are permitted in downhole materials in the region radiographed. Welds for our QTP-52, (Line Pipe grade material), QT-700, QT-800 and QT-1000 (Downhole materials), and HO-60 (Hang off materials) are made in this manner. The weld is dressed, stress relieved, and hardness testing is then performed in three regions. These regions are the weld itself, the heat affected zones, and the parent metal on either side of the weld. The hardness testing meets the requirements of ASTM A-370 and ASTM E-18.
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Finally, at customer request, the weld may be uniquely identified by acid etching. The entire process is shown in Figure 1-4. Upon milling, the weld is distributed along a helix in the finished tube. This geometry distributes the mechanical stresses experienced by the weld zone over the length of the helix rather than concentrating all of the stress in a single narrow band around the circumference of the tube. The performance of this type of weld is now proven in numerous applications in oil and gas wells, and in pipelines throughout the world.
Figure 47 Strip Bias Weld
Figure 48
The Forming Operation Pipe is manufactured from strip by the use of high frequency electric welding. First, the forming rolls of the mill are set for the diameter of the pipe. The first series of rolls encountered by the strip start bending the edges of the strip upwards, gradually forming a "U" shape. The next series of rolls have vertical EDC – Tomball, Version 1.01 Revised: April 2005
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fins which extend down past the strip edges. The strip is worked against these tungsten carbide fins to prepare them for the weld rolls. This is shown in the left hand part of Fig 4. Welding the Tubing The formed strip enters a high frequency induction welder where it passes into a coil excited by high frequency current. This current causes magnetic fields which in turn cause eddy currents to flow both around the longitudinal welded tube and back into the area where the strip is coming together. In this process, the heat for welding the edges is generated by the resistance to the flow of these eddy currents, which are concentrated at the edges by an internal ferrite core called an impeder. In this HF process, the heat is confined to a narrow band along the edges of the formed strip. A special set of insulated rolls squeeze the edges together while they are at the fusion temperature to produce the weld. In this process, no filler metal is added, keeping the metal composition of the weld line the same as the body of the tube. During the welding process, the tube is welded slightly oversized, and then reduced to final specifications in a set of sizing rollers. The tolerance on the outer diameter produced by this process is +/- 0.010 inch. Flash Removal The application of pressure in the fin pass rolls causes hot metal to be extruded towards the inner and outer diameter of the tube. Outer diameter flash is removed with a carbide cutting knife that is contoured to the diameter of the tube being produced. At customer request, inner flash is removed from pipe with IDs greater than 1.25 inches with a contoured cutting tool. This flash is subsequently pumped out of the tube. Inner surface flash removal leaves a slight groove, which does not reduce the wall thickness below the specified minimum wall. The finished flash removal process produces tubes the dimensions of which meet or exceed the requirements of API 5CT, API 5L, and API RP 5C7, the Recommended Practice for Coiled Tubing Applications.
Figure 49 Scarfing Tool
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Seam Annealer The longitudinal weld seam is immediately heated to 1650 deg. F by a narrow induction head in order to austenitize the weld and its heat-affected zone. This area will then have a uniform grain structure throughout. Full Body Stress Relief Heat treatment is performed in a full body stress reliever, in which the tube is heated to a predetermined temperature in the region of 900-1300 deg F for a specified time, determined by the final desired mechanical properties of the material. After air cooling and a final water cooling, the tube is wound onto a storage spool. Standard Services to Coiled Tubing String Length Measurement: The length of the string is continuously monitored throughout its production. The customer is provided with a length of tube which complies with +/- 1% of the specified length on the order, unless this restriction is waived by the customer. The finished string may be shipped on a blue QTI spool, bearing a QTI number, or transferred to a customer service rig in our covered service area. Welding Fittings: QTI will weld fittings onto finished tubing as requested by the customer – most common are 1502 2” WECO Thread. An external laboratory approves the welding procedures used for welding for each steel type and grade fabricated at QTI. Once welded, the integrity of the weld is verified by one or more of the following nondestructive testing techniques: • X Radiography • Magnetic particle inspection (ASME Section 5, Article 7) • Liquid penetrant inspection (ASME Section 5, Article 6) • These inspections may be performed to QTI's written practices or customer requirements. Tube-to-Tube Welding: In cases where the customer requires two shorter strings be joined together, and will accept a tube-to-tube weld, QTI will perform EDC – Tomball, Version 1.01 Revised: April 2005
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the weld to written procedures using qualified welders. Should the customer accept butt-welded sections of QT-700, QT-800 and QT-1000, they will be classed QT-70, QT-80 and QT-100 material respectively. Hangoff material and pipeline product may also be butt-welded. Nitrogen Purges and Blankets: Nitrogen is pumped through the coiled tubing, when the tubing is expected to be shipped overseas, or stored indefinitely, the ends are capped to maintain a blanket of nitrogen gas to help prevent the onset of internal corrosion. Crating: Should the customer require shipment on a QTI spool, the spool may be shipped as is, or crated for export.
Quality Tubing Pipe Sizes -Grades
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Coiled Tubing Fatigue Theory Coiled tubing may be considered a consumable product in the coiled tubing business line. As coiled tubing moves off and on the reel and passes over the gooseneck; fatigue is imparted on the coiled tubing. Ballooning of the coiled tubing may also occur. The number of bend reversals to pipe failure or maximum ballooning is dependent upon the following factors: • Bend radius • Internal pressure • Pipe material • Imperfections Bend Radius The tighter the bend radius the high the strain on the coiled tubing. As the bend radius decreases the number of cycles to failure decreases. Internal Pressure As the internal pressure increases the hoop stress imposed on the coiled tubing increases. As the pressure inside the coiled tubing increases the number of cycles to failure decreases. The failure characteristics for the various grades of coiled tubing will be different. Also, failure characteristics may be different between manufacturers of coiled tubing ie. QT-800 does not have the same fatigue characteristics as HS-80. For most materials as the pressure increases ballooning becomes much more predominant than fatigue. Pipe Material The fatigue life characteristics of coiled tubing will vary depending upon the grade of material and the manufacturer of material. Presently Precision Tube Technology and Quality Tubing Inc. are the two suppliers of coiled tubing. The high carbon, low alloy steels used to make the coiled tubing are typically classified by their minimum yield strength ie. 70 ksi, 80 ksi 90 ksi etc. The fatigue characteristics for each grade of pipe will differ as well as the fatigue life for an equivalent grade of pipe may differ between suppliers. EDC – Tomball, Version 1.01 Revised: April 2005
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Imperfections The origin of a fatigue failure is typically some sort of imperfection in the pipe. An imperfection in the pipe may be due to manufacturing methods, heat treatment, environment, handling, residual stresses etc. Imperfections result in stress risers. Increased stress translates into accelerated fatigue. A common stress riser may be a nick in the pipe or corrosion pit. Failure Due To Fatigue A fatigue failure usually begins with the development of a small crack transverse to the direction of tensile stress. The movement of the pipe on and off the reel and over the gooseneck results in the coiled tubing being subjected to alternating stress. Alternating stress causes the crack to open and close. Eventually the material is reduced to such a small area that it can no longer withstand the forces and breaks. Characteristically, the higher the internal pressure the more prominent the crack propagation. A cycle is defined as 6 bend reversals. These reversals are shown in
Figure 50 Fatigue Failure
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Bend 2: Enter Gooseneck Bend 1: Exiting Reel
Bend 3: Enter Injector
Bend 4: Exiting Injector
Bend: 5 Exiting Gooseneck Bend 6: Entering Reel
Figure 51 Fatigue diagram showing 6 bends making 1 cycle
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Ballooning Ballooning is described as the diametrical growth of the coiled tubing. As the diameter grows the wall thickness decreases. A decrease in wall thickness for a given pressure will result in increased hoop stress, which in turn magnifies the ballooning and fatigue of the coiled tubing. Ballooning will also cause the coiled tubing to be less resistant to collapse pressure. Excessive ballooning will result in the coiled tubing exceeding the stuffing box tolerances. This may result in coiled tubing damage or stuffing box brass damage. The maximum allowable ballooning limits are as follows: BJ Service’s Maximum Allowable Ballooning Limits Coiled Tubing Size (O.D.) (in.)
Ballooning Limit (in)
1.75” or less
0.05”
Greater than 2.00”
0.07”
Maximum Allowable Ballooning Limits
Being that ballooning is the diametrical growth of the coiled tubing, it can be physically measured. Ballooning is typically measured in thousands of an inch (1/1000”). As in the previous example, we can increase coil life by roughly 50 cycles if we enlarge the gooseneck to 90" or so. The existing large drum core diameter allows us this option without make any drum core modifications. Enhancing coil life can be accomplished by simply increasing the gooseneck size, but do logistical issues and modification costs outweigh the benefits? That is an operational issue. Other Ways to Increase Coil Life • Another way we can increase coil life is to increase the wall thickness. This reduces overall hoop stress, which increase the number of cycles to failure. It also increases pipe cost, pipe weight, spool weight, and required injector/spool torque. In order to investigate which is more effective increasing wall thickness or increasing drum core / gooseneck radius.
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• Increasing wall thickness has a greater effect when cycling at high pressure as opposed to low pressure. This is because the thicker walls reduce hoop stress which decreases the effects of dilation. • For thin walled pipe at high pressures, increasing goose neck radius beyond 90" has minimal effect on cycle fatigue. This is because dilation is the dominant damage mechanism for which goose neck size has little effect. • At high pressures, increasing goose neck size only impacts cycle fatigue of thick walled pipe. Chances are entire spools of thick wall pipe will never be used, but this information is still applicable to taper strings, where cycling normally occurs over the heavier walled portion of the string. • At lower pressures, increasing goose neck radius has a greater effect than increasing wall thickness. For example, Unit 5123, with a 90" drum core diameter (minimal dilation effects) and 72" goose neck radius, would reap greater benefits from increasing the goose neck to 90" versus increasing wall thickness all the way to .190". The relative logistical concerns must be more favorable for the goose neck option. Coiled Tubing Failures The goal of this section is to bring to light issues relevant to increasing coil life. By understanding all the factors pertinent to the topic, and generating discussions, we can hopefully optimize our coil life management. The three most prominent causes of coiled tubing failures are corrosion (35%), mechanical damage (22%) and manufacturing flaws (20%) – 2004 statistics. Presently, the issue of manufacturing flaws may not improve much at all, as the standards for milling coiled tubing are very high. Areas we can improve upon are mechanical damage and corrosion. Improvements in corrosion may consist of better storage inhibition procedures, pigging the coiled tubing to remove rust and debris and improving corrosion inhibition during acid treatments etc. Mechanical damage involves the handling of coiled tubing. Wrapping, injecting, transferring, shipping, improper equipment set-up etc. can all induce mechanical damage on the coiled tubing. This is an area we can improve upon. Note: Coiled Tubing pipe failures result in significant financial losses, not to mention potential risk of human life.
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Pipe Selection Criteria Coiled tubing pipe selection is critical to a coiled tubing business line. The size, grade and supplier of pipe you select will impact your coiled tubing business. In the past we have often relied upon work to define our string selection parameters. Due to advancements in coiled tubing research we now have scientific data to base our decisions on and a software program to analyze fatigue and ballooning of coiled tubing. Some of the considerations to be made when selecting a coiled tubing string are as follows: •
H2S? No = Any Material Yes = HS70 preferred
•
High D/t Ratio Required (light pipe)? HS90 and QT900 not recommended
•
Tapered String? No = Any Material Yes = QT1000 not allowed
•
QT 1000 Required? Internal Flash Removed Only (parallel string)
•
Pipe Size Greater Than 1 ¾”? QT800 recommended
•
High Pressure? HS90 not recommended D/t ratio < 15
•
Normal Cycling Pressure Above 4,000 psi? HS90 Not recommended
•
Normal Cycling Pressure Above 5,000 psi? HS not recommended
•
Majority of Cycling Below 3,000 psi? HS70 and HS80 recommended
•
Field Welding Required? 70 ksi or 80 ksi grades only
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As can be seen from the above bullet list there are a number of considerations to be thought through when selecting a string of coiled tubing. As with most decisions trade-off will be present. It is up to the individual to determine what the most critical parameters are and to recognize the pitfalls of the chosen string. For example, 70 ksi coiled tubing is often selected as a work string in Canada. The main reason behind this is due to H2S exposure. Many of the wells in Canada have H2S present. 70 ksi pipe is recommended for sour service. It would be beneficial at times to use a higher grade of pipe however the presence of H2S is determined to be the over-riding factor in the pipe selection process. NOTE: Due to increased awareness 80 ksi pipe is now being experimented with in the Canadian marketplace. However, 70 ksi pipe is still the preferred grade for H2S exposure. BJ Services developed a software program entitled CT MODELS; CT MODELS deals mainly with the ballooning and fatigue associated with coiled tubing. A number of scenarios or iterations can be run to determine the optimum pipe design, to suit the variety of work anticipated. Keep in mind, there are a number of factors to take into account when selecting a coiled tubing string. CT MODELS only provides insight to the question of fatigue, ballooning, equipment capacities and operating limits.
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CT Material Selection
H2S ?
Yes
No
OD > 1 3/4"
Yes
No
Cycling at < 3,000psi
Yes
Large Pull Capacity Required?
No
No Yes
HS90 Not Recommended
Yes
Cycling at > 4,000psi No
Yes
Tapered String?
Cycling at > 5,000psi
Yes
No
No
No
90 Grades Not Recommended
Yes
High D/t Ratio? (low weight)
No
Yes
Field Welding?
Yes
No
QT800
QT900
QT1000
No Specific Recommendation
HS90
HS80
HS70
Figure 52 Flow Chart For CT Pipe Selection
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Coiled Tubing Pre-job Simulation BJ Services Company has developed the CIRCA™ coiled tubing simulator over a period in excess of twenty years. The initial version of the software was used to improve well clean out capability using 1” coiled tubing and included two phase flow. This first generation program has evolved in to the state of the art software currently known throughout the petroleum industry as CIRCA™. As coiled tubing application evolved into a highly technical, multifaceted service, CIRCA™ been advanced to keep pace. A few enhancements to the capabilities of the program over the years have included • addition of a force and stress analysis section, • 3 dimensional modeling of well bore trajectories, • effects of residual curvature on coiled tubing, • apparent mechanical frictional drag, and • the effects of hydro dynamic drag of produced fluids on the coiled tubing. The latest version of this software, version 14, is now in constant use. This version incorporates superior graphics and data displays. Improvements to the engineering functions include the ability to model the effects of coiled tubing in buckled completions. Current application of CIRCA™ includes a variety of tasks from prediction of circulating and tubing force parameters through to history matching circulating and tubing force data on previously completed treatments. The main purposes of this program are to predict: • • • •
Flowrates and pressures when common oil field fluids are circulated in a well using coiled tubing The effects of solids transport on pressure and flow rates for cleanouts Forces acting on and stresses induced in the coiled tubing during Running In Hole, Pulling Out Of Hole and under stationary load conditions Operating limits in terms of weight indicator readings thereby defining a safe zone of Operation.
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CIRCA™ Circulation Analysis Enron India, Well: PF-2H Production Parameters - 1.5" CT in Hole
Output from a flow analysis includes:
(d) (e)
2500
500
2000
400
1500
300
1000
200
500
Oil Rate (bbl/day)
(b) (c)
Hydrostatic and friction pressure gradients Velocity (of each phase present) Gas volume fraction/foam quality and flow type for two phase flow Reynolds number Effective viscosity and shear rate
600 PI = 3852 scf/day/psi GLR = 115 bbl/MMscf No circulation thru CT
Pressure (psi)
(a)
3000
100 WHFP BHFP Oil Rate
0 0
0.5
1
1.5
2
2.5
0 3
Gas Rate (MMscf/day)
All of the above listed parameters are output at various measured depths between the wellhead and bottom of hole for both inside the coil and its annular. CIRCA™ Tubing Force Analysis The forces experienced by a workstring vary along its length according to a large number of variables, some of which are quantified by the circulation model, i.e.
•
Fluid and gas densities (used in the calculation and buoyancy and gravitational forces) Hydrostatic and friction pressure gradients
50000
40000 Surface Weight Friction Lock
30000
Operating Limit
20000
Max. Depth @ 14,800 ft
10000 Weight (lbf)
•
0
-10000 Simulated Conditions:
-20000
Output from the tubing force analysis includes: • • • • • • • • •
Production: 15 MMscf/day Wellbore: Gas Filled Friction: Tubing @ 0.23 Open Hole @ 0.35 2 3/8" Coiled Tubing Workstring: Gas Filled
-30000
-40000
-50000 0
2000
4000
Weight indicator gauge reading Weight indicator gauge reading at operating limits Wellhead pressure String pressure String injection pressure Friction force Tension force Triaxial stress Spiral pitch • Collapse differential limits
6000
8000
10000
12000
14000
16000
18000
Depth (ft)
All of the parameters output from CIRCA™ are available in report form or graph. EDC – Tomball, Version 1.01 Revised: April 2005
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CYCLE™ - COILED TUBING FATIGUE MANAGEMENT The purpose of the CYCLE™ program is to accurately estimate the life span of coiled tubing strings based on fatigue, ballooning and corrosion. All of the activity that the coiled tubing has been exposed to is recorded in a string file. A mathematical model of fatigue determines the life expectancy of the coiled tubing. Accurate knowledge of tubing damage can prevent fatigue related coiled tubing failure. The CYCLE™ program enables BJ Services operations to: • ability to provide real time on the job string history update • compile a complete history of work string activities including jobs, runs, maintenance activities, and coiled tubing failures • assess the service for which each existing string is currently fit based on fatigue, ballooning and corrosion calculations • view graphs and reports that summarize the history of each string including the estimated fatigue and the safe working life remaining The information that is input into CYCLE™ is stored in a string file. The string file provides a history of all the activity that the coiled tubing has been exposed to, from the date it was purchased until the date it is taken out of service. It also provides an assessment of the resultant tubing damage, including how much use of the string remains. The fatigue and ballooning calculations used to determine tubing damage are based on the data provided by the string file. They are only as accurate as the data provided. String file data is critical to safe and efficient coiled tubing operations. Accurate knowledge of tubing damage can prevent fatigue and related coiled tubing failure.
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CYCLE™ works in conjunction with another program called CYCLE DB™. The CYCLE DB™ program manages the information captured by CYCLE™.
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Monitoring Equipment Monitoring, recording and control equipment is crucial to job performance. For this reason, BJ uses the most advanced instruments in the field to monitor job progress. Among them being: Job Master BJ Services provide a unique data acquisition system capable of recording, monitoring and displaying all necessary information during coiled tubing operations. The system is designed to interact with the coiled tubing well model and the cycle/fatigue life program to perform real time update during the job. In addition, the system is simple to maintain, interacts with all standard computing equipment and above all, is user friendly. A Windows driven software program has been developed to ensure simplicity of operation and download of information. The unique display and keyboard allows our Engineers or Operators to interact with the system to change operating parameters if well conditions change. This provides an environment where decisions are taken that guarantee safety, maximize efficiency and ensure well integrity. Information can be downloaded via a CD or large capacity 100 Mb zip disk and then printed out via a standard computer in the field or back in the office. Wireless LAN The BJ Services Wireless LAN System replaces well site LAN cabling with radio links allowing for zero time deployment at the wellsite of treatment data communication. The units directly replace BJ LAN cables or may be used interchangeable with LAN cables. Since cabling is not used, the problems with maintaining conventional cables are eliminated and the reliability of the signals are improved. Features and Benefits • Operates in extremely harsh environments with immunity from interference. • Eliminates the need to run LAN cables between units and the time it takes to lay, retrieve, clean and store these cables. • Supports wireless data transmission between 3305 and remote computers via the computer serial port. EDC – Tomball, Version 1.01 Revised: April 2005
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Figure 53. Wireless LAN
Figure 54. Wireless LAN
Wireless Wellhead Unit The Wireless Wellhead Unit provides complete monitoring capabilities at the wellhead without the need for cable’s running back to the control cabin. The Wireless Wellhead Unit is designed to operate with BJ's JobMaster system. The unit is approximately 5 1/2 feet high. Power Center link for BJ monitoring & miscellaneous equipment: https://powercenter.bjservices.com/__86256d48004debc5.nsf/WebByCatego ry?OpenView&Start=1&Count=30&Expand=1#1
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Health and Safety
Continuously improved job procedures and commitment to Health, Safety and Environment, complete with regular audits, provide a safe and healthy working environment for all staff and client representatives, both on and off locations. Regular safety drills keep staff alert to their responsibilities, whilst structured training programmes highlight the safety aspects of their work, ensuring that HSE remains a primary consideration in all aspects of job design, preparation and execution.
Figure 54. 1st Bowen Injector Head
Figure 55. Before!
Figure 56. After?
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Acknowledgements: The author would like to thank Tomball’s Training Department: References: BJ Operations and Maintenance Manuals for Coiled Tubing Equipment BJ Services Training and Product Sales Material Coiled Tubing Operations & Procedures Manual (COP’s) – Eng 110 Fundamentals of Coiled Tubing Manual API Recommended Practice for Coiled Tubing in Oil and Gas Well Services BJ Services Iron Manual - Link BJ Services Products & Services Link Quality Tubing - Link Hydra Rig - Link, Texas Oil Tools - Link – Varco.com
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