Coiled Tubing

Exploiting of Coiled Tubing

Course Contents • Coiled Tubing Basic Components • Coiled Tubing Applications & Forces Distribution • Thru Tubing Coiled Tubing Services • Common Do’d and Don’t

What is the Coiled Tubing Unit? Coiled Tubing Unit is a portable, hydraulically powered service system which is designed to inject and retrieve a continuous string of tubing concentric to larger ID production pipe or casing strings. At the present time, coiled tubing constructed for well servicing application is available in sizes ranging from 0.75”OD up through 3.5” OD.

Elements of the Coiled Tubing Unit

Coiled Tubing Equipment • The basic configuration of a coiled tubing equipment package is dependent on: – Operating environment • e.g., offshore, arctic, desert

– Primary applications • e.g., units prepared for CTD operations will typically be larger than conventional service units

– CT string dimensions • e.g., string length/OD and necessary reel dimensions

Basic Equipment Configurations • Service companies equipment fleet comprises CT units designed to operate: • Onshore – Paved road trucks (road legal for operating area) – Off-road trucks (all-wheel drive, e.g., desert) – Mobile mast units (special environment, e.g., arctic) • Offshore – Skid mounted units (crash-frame protected) – Barge mounted units (permanent placement) – Jacking barge/tender vessel

CTU – Paved Road

Trailer mounted CTU

CT Express

Trailer mounted CTU

CTU – Off-Road

Truck mounted (6 x 6) CTU

CTU – Mobile Mast

Self propelled mast unit for desert operations

CTU – Mobile Mast

Trailer mounted mast unit for arctic operations

CTU – Skid Mounted

Skid mounted for offshore operations

CTU – Skid Mounted

Skid mounted for onshore/offshore operations

CTU – Barge Mounted

Lake Maricaibo barge mounted unit

CTU – Jacking Barge

Gulf of Mexico jacking barge

The Coiled Tubing Unit • Physical Characteristics – Self Contained – Mobile/Modular – Hydraulically Powered – Environmentally Friendly

• Operations – – – –

Injects and retrieves a continuous string of tubing into the well Can continuously pump fluids into well while moving pipe Land or offshore system designs No workover rig required when using CT

– Can be and is typically used on live wells(no kill fluids

introduced into well)

Coiled Tubing Advantages • Efficiency – Self-Contained unit, requires no rig – Saves time and money - do not have to kill well

• Reduced potential damage to formation – Typically used on live wells so no kill fluids necessary – Act as tool transport medium for deviated & horizontal wells

• Performance – Computer programs to optimize job design – Fast – Utilize internal pressure to generate large downhole forces

• Tubing Management – Advanced data acquisition system to monitor key job parameters on tubing management

INDEX • • • • • •

Surface Equipment. Well Control Equipment String Design and Service Life. Forces Encountered. Well Control Procedures. Applications.

CT Surface Equipment & Performance Specifications The basic components of a coiled tubing unit are as follows: 1) Injector 2) 3) 4) 5) 6) 7) 8)

Tubing Guide Arch Service Reel. Power Supply / Prime Mover. Control Console. Control and Monitoring Equipment. Down hole Coiled Tubing Connectors. Well Control Equipment.

1- Tubing Injector The injector assembly is designed to perform three basic functions: 1) to provide the trust required to snub the tubing into the well against pressure or to overcome wellbore friction 2) to control the rate of lowering the tubing into the well under various well conditions. 3) to support the full weight of the tubing.

Injector Head – Principal Components • Primary components/functions include: – Hydraulic drive/brake system (1) – Drive chains and tensioners (2)

– – – –

Gooseneck or guide-arch (3) Weight indicator sensor (4) Depth system sensor (5) Stripper mount (6)

3

1

5

2 4

6

Chain System – Hydra-Rig 1

• Typical chain system includes: – – – –

Drive sprocket/system (1) Inside tensioners (2) Outside tensioners (3) Lower idling sprocket (4)

2

3

3

4

Injector Basics • Hydraulically powered counter rotating chains. • Linear beam to apply grip to tubing • Roller chain around linear beam to transmit load to gripper blocks and then to tubing • Gripper blocks mounted in hardened steel counter rotating chain assembly • Hydraulic cylinders apply beam pressure to tubing • Bi-directional, twin hydraulic motors with gear reduction in upper assembly • Injector designation based on maximum pull capability, i.e., 30K can pull 30,000 pounds

Injector Specifications • Maximum Pulling Force: Is the max. tensile force that the injector can apply to the C.T. • Maximum Snubbing Force: Is the max. compressive force the injector can apply to the C.T. • Maximum Traction: Is the max. axial force that the injector can apply to push or pull the C.T. • Maximum Speed : Is the max. rate at which the injector is capable of deploying tubing into the wellbore (R.I.H) or extracting the tubing out the wellbore.

• Chain-gripper blocks: • these gripper blocks are designed to minimize damage to the C.T. and may be - machined to fit the circumference of the C.T. or - Cast in a “V” shape to accommodate variable OD sizes of C.T. Chain link pins

Roller bearing

Chain link plate and split pin Typical Injector Chain System

Gripper block

V-Block Grippers • Multiple tubing sizes can be run with the same gripper blocks • Grooved surfaces for enhanced gripping performance • Reduces cost of operations by not having additional gripper blocks for all size tubing. • It’s grove not a half circle which avoid damaging the CT & can be used in a range of CT sizes

Advanced Chain Components – HR 480

HR 480 Chain components variable insert

Types of Chain Drive • The chain drive assembly operates on the principle of frictional restraint, in that the C.T. is loaded by the opposing gripper blocks with sufficient magnitude of applied normal force that the resulting tangential friction forces are greater than the axial tubing loads (tension or compression).

• This applied normal force can be provided by one of three ways.

1- set of skates. 2- cam roller or skate roller. 3- dual chain traction loading system.

Injector Head – Typical Specifications Injector Head Model HR 240 HR 440 HR 480 SS 800

Dr

Capacities • Min. tubing size 1 • Max. tubing size 1-1/2 • Max. pulling force 20,000 • Max. snubbing force (lbf.) 10,000 • Max. running speed (fpm) 200

1-1/4 2-3/8 60,000 20,000 240

1-1/2 1-1/4 1-1/2 3-1/2 3-1/2 3-1/2 100,000 80,000 120,000 40,000 40,000 40,000 150 150 160

• • • • •

55 52 80 7,800

64 64 109 12,650

Dimensions Length (in.) Width (in.) Height (in.) Weight (lbm)

53 34 65 3,400

56 52 76 6,500

64 62 100 22,000

15K Injector

30 K Injector

80K Injector

2- Tubing Guide Arch The tubing arch supports the tubing through the 90 °bending radius and guides the C.T. from the reel into the injector chains. API Recommendations Tubing Size Radius (in.) (in.) 1-1/4 48 to 72 1-1/2 48 to 72 1-3/4 72 to 96 2 72 to 96 2-3/8 90 to 120 2-7/8 90 to 120 3-1/2 96 to 120

Tubing Guide (Guide Arch) • Guides tubing into injector • Large radius for best tubing life • Designed for all typical job set-ups and conditions

25111-281C

Weight Indicator Sensor

Front sensor/pivo t

Rear sensor/pivo t

HR 480 dual weight indicator sensors

Stripper Mounting Point

HR 480 stripper mount

Injector Head – HR 240

Injector Head – HR 480

3- Service Reel • The services reel serves as the C.T. storage mechanism during transport and as the spooling device during C.T. operations. • The rotation of the service reel is controlled by a hydraulic motor. • During R.I.H. slight back pressure is kept on the reel to allow the injector to pull the tubing off of the reel (reel back-tension). • During POOH. This pressure is increased to allow the reel rotation to keep up with the extraction rate of the tubing injector.

CT Reel – Functions • Basic functions of the reel or equipment normally mounted on the reel include: – Storing and protecting the CT string (drum) – Maintaining proper tension between reel and injector head (reel drive system) – Efficiently spooling the CT string on to the reel drum (levelwind system) – Circulating fluids with the drum rotating (swivel) – Application of protective coating or inhibitor on tubing string (tubing lubricator system) – CT depth measurement system (reel mounted counter)

CT Reel – Primary Components 5

• Typical reel components: – Reel drum (1) – Reel drive system (2) – Levelwind assembly (3) – Reel swivel and manifold – Lubrication system (4) – Depth counter (5)

3

1

4

2

Reel Models and Capacities Hydra-Rig Reel Model/Configuration

Tubing Size

1015

2015

3015

3020

4122

1-1/4-in. 1-1/2-in. 1-3/4-in. 2-in. 2-3/8-in.

15,000 10,000 N/A N/A N/A

22,500 15,100 11,200 8,500 N/A

25,000 22,000 15,000 11,000 N/A

25,000 25,000 20,000 15,000 N/A

25,000 25,000 25,000 22,500 15,300

Reel Drum Capacity Capacity of reel drum: L = (A + C) (A) (B) (K) Where: L = Reel capacity (ft) A = Tubing stack height (in.) B = Drum width (in.) C = Core diameter (in.) K = Constant (tubing size dependent) 1-1/4 = 0.168 1-1/2 = 0.116 1-3/4 = 0.086 2 = 0.066 2-3/8 = 0.046

Freeboard

A

C

B

Reel Models

Reel size comparison

Reel Drive and Brake Systems

Spoked reel Floor mounted motor/brake

Dished end reel Axle mounted motor/brake (Levelwind system pump shown)

Levelwind 3System 2

• System components include: – Drive chain/system (1) – Override motor (2) – Spooling head (3)

1

Reel Swivel and Manifold with E-Line Cable

Pressure bulkhead

Coiled tubing

Jumper cable

Reel collector

Reel axle

CT isolation valve

Reel swivel

60K Embedded Reel

Truck Mounted Reel

Truck (self propelled mast unit) mounted reel

Skid Mounted Reel

Skid mounted, crash-frame protected reels

Completion Spool

Completion spool (3-1/2-in. CT) with custom built spooler

Depth System Sensor

Spring mounted assembly and friction wheel

Assembly (including electrical encoder)mounted at base of injector head

Typical depth sensor mount (HR 480)

Level Wind

Importance of Accurate Depth • •

•

Current CT Depth System has accuracy only of 0.5% Inaccuracy caused by slippage, sensitivity to misalignment and wear on depth wheel, while repeatability is very poor. New system has accuracy of 0.03%, through dual wheel concept, slip detection, harder material

4- Power Pack/Control Cabin – Functions • Basic functions of the power pack/control cabin or equipment normally mounted therein: – Providing hydraulic power required by the CTU (engine and hydraulic pumps) – Control and limitation on hydraulic systems (hydraulic control and relief valves/system) – Hydraulic accumulator storage for secondary well control equipment (BOP accumulator) – Enables control and monitoring of all operating systems from a single operator’s station (control console) – Providing operations data to enable wellsite design and monitoring

Power Pack – Primary Components • Power Pack – Engine – Hydraulic pumps – Hydraulic control systems – Onboard accumulators • Control cabin – System (CTU) instruments and controls – Well/operation monitoring and recording equipment

Layer 1 T emperature High Coolant

High Exhaust Tem perature

Low Oil Pressure

Oil Pressure

Coolant Tem perature

Permissive start

Loss of Coolant

Engine Tac hometer

Start Engine Emergenc y Kill Kill

Air Pressure

Prime Mover • In general, the prime mover packages are equipped with diesel engines and multistage hydraulic pumps which are typically rated for pressures of 3,000 psig to 5,000 psig. And in addition, the accumulator package for well control equipment.

5- CTU Instruments and Controls – Primary instruments and controls • Weight indicator, circulating and wellhead pressures

– Secondary instruments and controls • Depth/speed indicator, chain tensioner pressures, stripper system pressure

– Support instruments and controls • drive system pressures, BOP system pressure, and additional systems

Control Console

Control Console

Control console

Control Console System gauges

Principal gauges CLOSE

BOP PRESSURE

STRIPPER #1 PRESSURE

BOP SYSTEM PRESSURE

STRIPPER #2 PRESSURE

STRIPPER SYSTEM PRESSURE

OPEN

INSIDE TRACTION PRESSURE DRAIN

STRIPPER SYSTEM PRESSURE

SYSTEM AIR PRESSURE

TUBING WEIGHT INDICATOR STRIPPER BLEED

BLEED

OUTSIDE TENSION INJECTOR

BLIND RAM

SHEAR RAM CLOSE OPEN

PRESSURE

NEUTRAL

CLOSE OPEN RETRACT

CLOSE OPEN

B O P

ON

CHARGE PRESSURE

OFF

ON

CLOSE OPEN

PRESSURE ADJUST

INJECTOR LUBE HIGH

LOW

REEL LUBE ON

OFF

OFF TOP TRACTION

IN

INJECTOR TOP TRACTION CYL.

INJECTOR 2 SPEED

ENGINE STOP

REEL BRAKE REEL BRAKE PRESSURE

NEUTRAL RETRACT

PACK ON

AUX BOP CLOSE OPEN

BOP SUPPLY ON

OUT INJECTOR MIDDLE TRACTION CYL.

INJECTOR PRESSURE ADJUST

REEL PRESSURE ADJUST

OFF

INJECTOR SLOW SPEED CONTROL ON STRIPPER PRESSURE ADJUST

BOP and stripper systems

EMERGENCY STOP

Schlum berger Dowell

OFF MIDDLE TRACTION

STRIPPER #2

CIRCULATING PRESSURE

INSIDE TRACTION

INJECTOR CONTROL PIPE RAM

PRIORITY PRESSURE

DEPTH SYSTEM WELLHEAD PRESSURE

EMERGENCY TRACTION SUPPLY

PACK STRIPPER #1

SLIP RAM

INSIDE TRACTION SUPPLY PRESSURE

THROTTLE

OFF BOTTOM TRACTION INJECTOR BOTTOM TRACTION CYL.

INJECTOR CONTROL PILOT PRESSURE

INJECTOR MOTOR PRESSURE

REEL PRESSURE

Injector head and spooling controls

LEVELWIND LEVELWIND OVERRIDE ARM

REEL CONTROL AIR HORN

Reel drive controls

Control Console

Control console - split angle

Control Console – CTD Unit

Advanced control console - CTD control cabin

6- Control & Monitoring Equipment Critical Job Parameters

A- Load Measurement. B- Depth Measurement. C- Speed Measurement. D- C.T. Inlet Pressure. E- Wellhead Pressure. Computerized Data Acquisition system used ( CDA )

7- Downhole C.T. Tool Connections Non Yielding Connection: – slip type : which requires the use of a slip or grapple-type load ferrule placed on the OD of the tube body. – thread type: connection which is secured to the C.T. with threads.

7- Downhole C.T. Tool Connections Yielding Connection: – dimple type : which is secured onto the C.T. body through the use of numerous mechanical screws. – Roll-on type: connection which incorporates a machined insert mandrel designed to fit inside the C.T.

Pressure Control Equipment

Well Control Stack • The well control stack is composed of the stripper assembly and a minimum of four hydraulically -operated rams. The four ram components are equipped (from top down) with, – Blind Rams: are used to seal the wellbore off at the surface when well control is lost. – Shear Rams: are used to mechanically break the C.T. In the event the pipe gets stuck. – Slip Rams : are used to support the weight of the pipe below. – Pipe Rams: are used to isolate the welbore annulus pressure below.

Pressure Control Equipment • Pressure control equipment associated with mobilization of a basic CTU for routine service activities includes: – Stripper • generally permanently mounted on the injector head

– Blow-out preventers • quad configuration most common

– Riser, lubricator • application dependent

– Auxiliary equipment • wellhead crossover(s), flow “T”, kill line and valves

– Downhole check valve • preventing back-flow of wellbore fluids

Pressure Control – “Without Control”

Situations to avoid No. 1

Coiled Tubing

Situations to avoid No. 2

Coiled Tubing – Uncontrolled Release

Situations to avoid No. 3

Pressure Control/Barrier Philosophy Injector head Primary barrier Secondary barrier

Tertiary barrier

Stripper (possible dual) Quad BOP

Shear-seal BOP

Swab valve and wellhead

Stripper – Functions • The primary stripper typically performs the following functions: – Maintain a primary barrier against wellbore pressure and fluids – Secure and align the injector head with the pressure control and wellhead equipment – Support the tubing between the injector head chains and the stripper seal

• Design features enable: – Servicing of consumables (sealing elements) with CT in place – control/actuation of primary seal without reliance on CTU power pack engine

Stripper Configurations • Basic stripper configurations are available – Conventional – Side Door – Side Door Tandem

Conventional Stripper – Components Tubing support/top access

Packing assembly Hydraulic system

Mounting flange

Lower connection Typical packing stack

Side-Door Stripper – Components Tubing support

Hydraulic actuation system

Access window – with safety lock, stripper packing assembly and back-up seal

Interlocking stripper inserts Lower connection (flange option)

BOP – Functions • The following functions and requirements typically apply to CT BOPs: – Provide a secondary barrier against wellbore pressure and fluids (pipe rams and shear rams) – Secure/support the tubing string against the operating weight or snubbing force (slip rams) – Shear the tubing string under operating conditions (shear rams) – Provide wellbore access for fluid (kill port) and pressure measurement (pressure port) – Support the weight (and forces applied) of the CT equipment under the rated wellbore pressure

Quad BOP – Components Upper flange/connection adapter Pressure port Equalising valve

Blind rams Shear rams

Kill port Slip rams Equalising valve

Pipe rams

Lower flange/connection adapter

Combi BOP – Components Pressure port Equalizing valve

Upper flange/connection adapter Blind/shear rams

Kill port Equalizing valve

Pipe/slip rams Lower flange/connection adapter

Blind/Shear Ram Ram seal Ram body Ram seal

Shear/seal blades

Retainer bar

Shear/seal ram components

Shear-Seal BOP • Functions – Tertiary barrier against well bore fluids and pressure – Remote actuated safety device (last ditch)

• System Design Features – Independent supply/accumulator system – Heavy duty shearing ability

Shear-Seal BOP – Components

Shear seal BOP

Stack Configuration Factors • Factors influencing stack configuration: – Location • e.g., offshore, onshore and local regulatory requirements

– Application • e.g., wired CT, perforating, fluid circulation requirements

– Worksite limitations • e.g., height, crane capacity, riser/lubricator stability

– Wellbore conditions • e.g., high pressure, high temperature

– Tool string dimensions • e.g., length and OD

Pressure Control Stack Requirements • The basic requirements of a pressure control stack will typically include: – Provision of required number of barriers • e.g., secondary or tertiary barrier

– Kill port(s) or means of circulating well control fluids • i.e., fluid port located beneath sealing rams

– Pressure port or monitoring capability • i.e., ability to monitor wellhead pressure with sealing rams closed

– Appropriate contingency and redundancy • e.g., tandem stripper or dual valves on kill and circulation ports

Auxiliary Pressure Control Equipment • Auxiliary equipment commonly used to configure appropriate pressure control and fluid handling capabilities: – – – – –

Riser/lubricator Wellhead adopter flange(s) Pump in “T” Hydraulic actuated kill-line valves Hydraulic riser/lubricator connectors • Hydraulic “Quick Latch” – Specialised deployment equipment • Riser window

Riser/Lubricator • Key features or factors for selection: – Construction • e.g., solid block – Connection • e.g., size and compatibility – Pressure port or vent • e.g., for gauge or bleedoff facility – Loading • forces and stability

Flanged riser

Pin and collar lubricator

Wellhead Adapter Flange

Wellhead adapter flange features

Flow Cross or Pump-In “T”

Flow cross with hydraulic and manual valves (flanged connections)

Quick Latch – Function • Principal functions of hydraulic connectors include: – Enabling riser/pressure control connections to be made without exposing personnel to suspended loads – Enabling a rapid connect/disconnect facility which expedites rig-up/down time (e.g., faster BHA change outs) • Design features include: – Positive indication of locking – Capable of withstanding/transmitting normal forces resulting from internal pressure and equipment weight

Quick Latch – Components Quick latch stinger flanged to upper stack assembly

Quick latch body flanged to lower stack assembly

Hydraulic quick latch

Well Control Procedure • The principle of well control is to maintain a safe working condition when performing intervention services. • Well control equipment components 1) one stripper or annular-type well control component. 2) one blind ram well control component. 3) one shear ram well control component 4) one kill line outlet with isolation valve(s) 5) one slip ram well control component. 6) one pipe ram well control component. • The kill line outlet on the well control stack should not be used for taking fluid from the wellbore.

Pressure Control Stack Examples • Common examples of pressure control equipment stacks: – – – – –

Onshore – standard Onshore – with quick latch Offshore – platform or jack-up Offshore – semi submersible High pressure applications • 7,000 psi • 10,000 psi

Onshore – Standard Upper BOP adapter

Quad BOP Lower BOP adapter Swab valve and tree

Injector head

Stripper

Onshore – Quick Latch Quick latch body

Quad BOP Injector head

Lower BOP adapter Swab valve and tree

•

Stripper Quick latch pin

Offshore – Platform or Jack-up Riser section Injector head

Flow cross or “T” Wellhead crossover

Primary stripper

Shear-seal BOP Wellhead

Secondary stripper

Quad BOP

Offshore – Semi-submersible

Connector stinger assembled on flow head

Flowhead or test tree assembled on tubing string or subsea riser

BOP and quick latch assembled on lifting frame mount

Injector head supported within lifting frame

Hydraulic releasing connector

High Pressure – (<7,000 psi) Flow cross with choke/kill lines equipped with hydraulic control valves

Tertiary shear/seal and pipe slip rams (may be combi)

Injector head and stripper assembly fitted with injection port

High Pressure – (<10,000 psi) Flow cross with choke/kill lines equipped with hydraulic control valves Tertiary shear/seal and pipe slip rams (may be combi)

Injector head and dual stripper assembly fitted with injection port

String Design and Service Life C.T. Material In the manufacturing of C.T., High Strength low alloy (HSLA) steels are commonly used to achieve the desired.

-Weld ability - corrosion resistance - fatigue resistance - mechanical properties

HSLA Carbon Steel (by weight percent) Carbon C Manganese Mn Phosphorus P Sulfur S Silicon Si Chromium Cr Nickel Ni Copper Cu Molybdenum Mo Aluminum Cb-V

Modified ASTM A606 Type 4 0.08 0.15 0.60 0.90 0.03 Max 0.005 Max 0.30 0.50 0.45 0.70 0.25 Max 0.40 Max 0.21 Max -

Modified ASTM A607 0.08 0.17 0.60 0.90 0.025 max 0.005 max 0.30 0.45 0.40 0.60 0.10 Max 0.40 Max 0.08 0.15 0.02 0.04

Tapered C.T. Strings • In general, it’s uniform O.D. and variable I.D. to provide enhanced performance in services. 1) Used to increase the maximum operating depth of a string.

2) Used to enhanced stiffness, buckling resistance and in service required the operation of downhole tools.

Tapered C.T. Strings 3) The change in the wall thickness should not exceed 0.008” 0.022”

for W.TH. for W.TH.

Below Above

0.110” 0.110”

Bend Cycle Fatigue Departing Methods. 1- The “RUNNING FEET” Method The footage of the C.T. R.I.H. is recorded for each job. And then added to the existing record of footage. Values ranges from (250,000-750,000) ft.

2- The “TRIP” Method The C.T. string divide into section, from (100-500) ft. long, the number of strips over the tubing guide arch for each section can then be tacked and recorded, included the effects of internal pressure loading. With this type of analysis its possible to identify the C.T. section, which have experienced the most bend-cycle fatigue damage.

Analysis of Bend Cycle Fatigue for C.T. 1) The working life of the C.T. can be extended by increasing the bend radii of the tubing guide arch and reel core for a special tube diameter size. 2) The working life of any size of C.T. can be increased by selecting a tube with a thicker wall. 3) The working life of the C.T. can be extended by increasing the material yield strength of a tube. 4) In comparison, as the OD size of the C.T. increases, the working life (B-C) decreases.

Corrosion in C.T. Service • Corrosion occurs to the C.T. as a result of exposure to the atmosphere or through metal loss from pumping corrosive fluids. Corrosion Effects: 1) wall thinning and pits >> reduce C.T. strength 2) reduced pressure integrity in collapse and yield pressure. 3) poor seal capability at the stripper and control components.

Corrosion in C.T. Service • Corrosion Effects: 4) when running C.T. in a wellbore environment with H2S in brine, it is recommended to add an inhibitor to the circulating fluids.

C.T. Collapse Pressure Derating • As manufactured coiled tubing will have near 100% roundness as the CT. is continually worked onto & off the service reel and over the tubing guide arch the ovality of the pipe typically increases. (Ovality is the major factor in derating tubulars for collapse presure).

• When tubing is subjected to varying degrees of tensile loads, the ability of the pipe to resist collapse is diminished. • As applied tensile loads approach the min. yield strength of the tube , the pipe will undergo permanent strain and “neck-down” at the point of max. applied stress. Once “necking-down” occures, the pipe loses its principal strength and becomes susceptible to collapse at pressures below the calculated pressure. Also this region will have a reduced burst pressure rating pressure rating than the reminder of the pipe string.

Forces Encountered During C.T. Services

• there are many forces which affect the behavior of the tubing. – Well pressure Fwp – Tube weight Fw – Buoyancy

- Tubing drag FD - Stripper element FP - Chain drive force FC

NUBBING: when well pressure creates an upward force > the weight of the tubing . (pipe light) Operation.

STRIPPING: when well pressure creates an upward force < the weight of the tubing. (pipe heavy)Operation,

C.T. Stability AND Physical Behavior • Compressional forces in excess of the specific critical load applied to an unsupported section of C.T. will cause the pipe to buckle. (sinusoidal) as thurst loads increase from the surface the pipe will form a helix. • Once the pipe is forced into a helix, the thrust required moving the C.T. increases because the increase of wall frictional drag until it overcome the thrust loads (lock-up) • once lock-up occurs , the C.T. will fail in shear wherever the critical buckling angle had developed. • There are two types of buckling failure (major axis buckling and local buckling) locate at: 1)

2)

between the top of the stripper and lowest fully-supported chain gripper block. within a large diameter borehole.

Minimum Documentation required

Minimum Documentation required for

Tubing injector head, well control system, valve arrangements, riser, lubricator, spools, high pressure piping and hoses, high pressure vessels:

Minimum Documentation required for

Coiled tubing string

Minimum Documentation required for

Downhole tools

Coiled Tubing Applications *

Pumping Operations

Deliver Fluid(s) at required rate and/or pressure at the target depth

* Mechanical Operations Deliver tool(s) to the target depth(s) Pull,push or activate a mechanism

* Permanent Installations

Coiled Tubing Applications (Continued)

Pumping Operations Unloading wells with Nitrogen Stimulating formations (Acidizing)

Removing Fill (Sand) Removing(Dissolving) organic deposits Isolating zones with cement

Cutting tubular with fluid Removing scale hydraulically

Coiled Tubing Applications (Continued)

Mechanical Operations Logging with CT Perforating Fishing Operating Slide Sleeve Setting bridge plug or packer

Running/Setting completions Removing Scale(milling)

Cutting Tubular

Coiled Tubing Applications (Continued)

Permanent Installations Velocity & Injectivity Strings

CT Completions Flowlines Umbilical

Conventional CT Applications

Features of Conventional Applications •

Conventional CT applications generally utilize the fluid conveying advantages provided by a CT string: –

Continuous circulation •

–

Circulation and string movement •

–

no interruptions for tool joint make-up unlimited movement while circulating

Precise depth control •

accurate spotting of fluids

Conventional CT Applications • CT applications typically considered as conventional: – – – – –

Wellbore fill removal Matrix stimulation treatments Squeeze cementing Well kick-off (nitrogen lifting) Basic scale, wax or paraffin treatment

Wellbore Fill Removal – – – –

Wellbore fill removal operations are designed to: Restore the production capability of the well Permit the free passage of wireline or service tools Ensure the proper operation of flow control devices • e.g., sliding sleeves or valves

– Maintain a sump (space) below the perforated interval • e.g., to allow complete passage of tools or as a contingency tool drop area

– Removal material which may interfere with subsequent well service or completion operations.

Wellbore Fill Materials • Wellbore fill materials include: – – – –

Formation sand or fines Produced propant or frac treatment residue Gravel pack failure Workover debris

• Condition of fill material may be: – Sludge or fine particles – Unconsolidated particles – Consolidated particles

Wellbore Fill Removal - Design Data • Job design data for wellbore removal is categorised as: – – – –

Reservoir parameters Wellbore and completion geometry Fill characteristics Logistical constraints

Obtaining accurate data during treatment design is crucial to the selection of optimum techniques, treatment fluids and ultimate success of the operation.

Fill Characteristics • Establishing the characteristics of the fill material can be the most difficult design data set to obtain. Useful information: – – – – – –

Particle size Material density Solubility Consolidation Estimated volume of fill material Presence of viscous material

Particle Transport • The ease by which a particle can be transported relates to: – Size • small is good

Drag

Buoyancy

Fill particle

– Density • less dense is good

– Fluid characteristics • can be complex

– Fluid velocity • don’t stop!

Weight

Fluid Selection • Considerations for fluid selection include: – Bottom hole conditions • BHP and BHT

– Particle carrying ability – Friction pressure • at necessary pump rate

– Disposal and logistic constraints – Compatibility • with wellbore and reservoir fluids

– Cost

Deviated Wellbores

Dunes formed as fill drops from fluid and slips down tubular

Wellbore fill material (bed)

• Particle behaviour in deviated wellbores

Fluid Types • Fluid types commonly used to circulate wellbore fill include: – – – – – –

Water/brine Oil/diesel Gelled fluids Liquid and nitrogen stages Foam Nitrogen gas

Fill Removal Fluids - 1 • Water/brine – Generally low cost – Ease of handling, recirculation may be possible – Good jetting characteristics, no static suspension – Possible compatibility problems

• Oil/diesel – – – –

Lower density Fewer compatibility problems (always check) Handling difficulties, no recirculation Disposal to production facilities

Fill Removal Fluids - 2 • Gelled Fluids – – – –

Water or oil based fluids Improved particle carrying and suspension Sensitive to wellbore conditions (fluids and temperature) Increased friction pressure - decreased pump rate

• Liquid and nitrogen stages – Suitable for lower BHP applications – Assists with high friction pressure difficulties – Complex pumping and tubing movement schedule

Fill Removal Fluids - 3 • Foam – – – – –

Best particle carrying and suspension capability Water or oil based Poor jetting ability Suitable for low BHP applications Complex equipment and pumping schedule

• Nitrogen gas – Limited application in very low BHP wellbores – Extremely high velocity required for particle carrying

Foam Quality 52%

FoamViscosity

Nitrified Liquid (Slugs)

85% Wet Foam

96% Dry Foam

Mist

Stable foam range suitable for fill removal operations 80 to 92% FQ.

Liquid Viscosity

Gas Viscosity

25

50

75

100

Foam Quality (%)

• Foam quality vs. foam viscosity Foam quality = gas volume / foam volume

Foam Equipment Rig-up

BOP kill port Pumping T below BOP

Nitrogen package

Production tubing Base fluid Process and recirculate (uncommon)

Choke manifold

Disposal

CT nozzle

Foam Equipment Rig-up

Downhole Tools • Possible specialist tools fill removal operations: – Jetting nozzles • matched to fluid rate and tubular size

– Drill motor • for consolidated fill or fill with scale etc.

– Impact drill • alternative to drill motor

– Junk removal • fishing tools or junk basket

CT String Movement • CT string movement should be coordinated with fluid pumping – Tagging fill • identify fill level to establish fill volume

– Penetrating fill • must be controlled to avoid overloading annulus • penetrate only when fluid is exiting nozzle (not gas) Fluid Type

Weight of fill/gallon of fluid (lbm)

Water

1

Gelled fluid

3

Foam

5

Computer Modeling • Wellbore Simulator (WBS) uses conservation of mass and momentum equations to establish: – – – – – –

Flow in or out of perforations Flow out of the wellbore choke (wellbore returns) Solids picked up by fluid Gas dissolution U-tube effects Transfer of heat

Equipment Requirements • Typical equipment requirements include: – Coiled tubing equipment • appropriate string size and length

– Pressure control equipment • configured for solids in circulated fluids

– Downhole tools and equipment • appropriate to fill characteristics

– Auxiliary equipment • fluid mixing, handling and pumping equipment

Treatment Execution • Wellbore fill removal operation issues can be categorized as: – Wellbore preparation • confirm fill type/status, e.g., recovery of fill samples • completion preparation, e.g., gas lift valve dummies • fluid loading or well kill

– Treatment and tool operation • monitoring density and volume of fluids pumped • multiple passes over key intervals

Fill Removal Evaluation • Evaluation issues may include reference to: – Operation objectives • increased flow • wellbore access • operation of completion equipment (sliding sleeve)

– Fill/solids recovered • volume (predicted vs. actual) • safe disposal

Matrix Stimulation

• The process of restoring the natural permeability of the near-wellbore reservoir formation by injecting treatment fluids at a pressure less than the formation fracture pressure.

CT Advantages in Matrix Stimulation • Advantages brought by the features of CT equipment and associated techniques include: – Live well treatments – Operations completed as an integrated treatment • e.g., fill removal prior to a treatment

– Protection of completion tubulars – Accurate placement (spotting fluids) – Selective treatments or diversion options • e.g., enhanced treatment of long intervals

Design • Principal treatment design considerations include: – Confirm candidate well is “damaged” – Identify location, composition and origin of damage – Acquire job design data – Select appropriate treatment fluid – Determine optimum treatment parameters (rate/pressure) – Determine treatment volume – Select appropriate diversion or selective treatment method – Prepare a complete pumping/treatment schedule – Forecast the economic viability of the treatment

Candidate Selection • Candidate selection confirmation requires investigation of: – Drilling • e.g., mud losses

– Completion • e.g., completion geometry

– Reservoir • e.g., contacts, temperature and pressure, por/perm

– Production • e.g., production test results

– Workover • details of previous interventions or treatments

Laboratory Analyses • Depending on wellbore/reservoir conditions, the following analyses may provide crucial design data: – – – – – – – – –

Acid solubility tests Formation water analyses Emulsion and sludge testing Iron content testing Permeability and porosity Flow test response (ARC) SEM/Edax Petrographic study Paraffin and asphaltene content

Formation Damage Damage Location

Tubing

Gravel Pack

Perforations

Formation

Type of Damage

Scales X Organic deposits X Silicates Emulsion X Water block Wettability change Bacteria X

X X X X X

X X X X X

X X X X X X X

Completion or Wellbore Characteristics • Completion and wellbore design factors include: – Ability to safely run and retrieve CT string in wellbore • deviation • doglegs

– Size restrictions • CT string and tool string OD • available flow rate

– Presence of fill or damaging material • wellbore fill preventing access • wellbore deposits producing unwanted reaction products

Treatment Fluid • Key factors in treatment fluid selection: – – – – – – – –

Physical characteristics of damage to be removed Reaction products Corrosion inhibition Fluid compatibility Fluid friction reduction Compatibility with diverting agent Clean up and flowback Preflush and overflush

Fluid Additives • Treatment fluid additives may include: – – – – – – – – – –

Corrosion inhibitors Alcohol Antifoam Clay stabilisers Diverting agents Formation cleaner Iron stabilizers Mutual solvents Organic dispersants Surfactants

Corrosion Inhibitors • Efficient corrosion inhibition is essential in all treatments using corrosive fluids. Factors influencing selection include: – – – –

Type and concentration of acid Maximum temperature Duration of acid contact Type of material (tubular/completion) requiring protection – Presence of H2S

Fluid Friction Reduction • Stimulation treatments performed through CT strings can benefit from fluid friction reducers by: – Improving flow (injection) rate as the perforations typically increases treatment efficiency – Reducing circulating pressure reduces fatigue induced during bending cycles – Reducing exposure time to corrosive fluids

Downhole Sensor Package • Real-time downhole data acquisition: – Accurate BHT and BHP – Helps determine efficiency of a treatment as it progresses – Enables design “on-the-fly” or “test-treat-test” operations – Optimises use of diverting agents – Optimizes treatment fluid volumes

DSP - Principal Components Plastic coated cable inside CT string

Cable clamp and check valve assembly

Mechanical release sub assembly

Pressure and temperature sensors

• DSP downhole tool components

Treatment ports/nozzl e

Diversion • Ensuring uniform distribution of the stimulation fluid across the treatment interval. Essential characteristics include: – – – –

Uniform treatment across varying permeability Non damaging to formation (temporary plugging) Rapid and complete clean-up Compatible with treatment fluids and techniques

• General techniques include: – Mechanical diversion – Chemical diversion – Foam diversion

Mechanical Diversion • CT matrix treatments are designed with the following mechanical diversion methods: – Bridge Plug • determines lower treatment limit

– Packer • determines upper treatment limit

– Straddle assembly (or combination of above) • selective treatment zone

Chemical Diversion • Chemical diverting agents: – – – –

Benzoic acid flakes Water or oil soluble salts Oil soluble resins Emulsifiers

• Features of chemical diversion techniques: – – – –

Tend to rely on high rate treatments Can be problematic to clean-up Particulates can interfere with CT tools High viscosity diversion fluids not compatible with CT

Foam Diversion • Foam diversion offers several advantages in CT applications - FoamMAT diversion service developed specifically for CT treatments. – – – –

Efficient diversion technique Fast and efficient clean-up Treatment designed to suit conditions Enables some flexibility to optimize treatment

FoamMAT Diversion Principles • FoamMAT process comprises five steps: – Clean near-wellbore region • clean up oil which will break foam

– Saturate near-wellbore area with foamer • to ensure a stable foam is generated

– Foam injection • 55 to 75% foam quality

– Shut-in (recommended) • reduces time to optimum diversion efficiency

– Inject treatment fluid (containing surfactant) • surfactant helps maintain foam quality

Execution Precautions • Precautions to be observed relate to: – Personnel and environment • e.g., protective equipment, mixing, spill protection

– Well security • e.g., H2S may be liberated following treatment

– Equipment • e.g., prejob pickle, postjob flush

– Post treatment • e.g., handling and disposal of returned fluids

Equipment Requirements – – – – –

Coiled tubing equipment Pressure control equipment Pumping equipment Monitoring and recording equipment Downhole equipment

Matrix Stimulation

Matrix Stimulation through Coiled Tubing Design, Execution and Evaluation aspects and considerations

Outline • Considerations during CT Stimulations • Challenges in Highly Deviated Wells • Selective Acidizing – Zonal Isolation with Packers – Foam Diversion

• Monitoring & Control of the Treatment • Case Histories

02

Considerations for Stimulation • Candidate Selection – Damage Removal • • • •

Inside Wellbore Perforation Tunnels Near Wellbore Matrix Reservoir

Coiled Tubing Coiled Tubing Coiled Tubing

– Creating new flow Paths • Dissolving Rock • Fracturing Rock

Coiled Tubing is typically used to remove damage only, due to its limited pump rate and excessive pressure drop. 03

Treatment Fluid • Sandstone Formations – Mud Acid Treatments (HF- HCL mixture) * Dissolves the damage * Typically more complex fluid systems * More corrosive to Coiled Tubing

• Carbonate Formations – Hydrochloric Acid Treatments * Dissolves damages and/or rock 04

Corrosion Inhibitors • Principal Function – To protect all tubulars and downhole components from corrosionduring the treatment, without affecting the injectivity or productivity of the treated formation. – Tubulars include Coiled Tubing • CT Considerations – Smaller tubing, additional tubing on drum, increased exposed area and higher internal velocities require consideration when selecting a schedule – Surfactants, Mutual Solvents and demulsifiers will alter the effective temperature range of inhibitors – Performance of inhibitors is significantly reduced in the 05 presence of H2S.

Injection Pressures & Rates • Pressures – As high as possible, not exceeding fracture pressure – Majority of surface pressure could be pressure drop through the CT – Friction reducers can significantly reduce surface pressures. – 4000 psi is currently the surface limit

• Rates – Should be as high as possible to get maximum utilization of the acid. – Rates are typically low, which results in long treatments 06

Matrix Stimulation Challenges in Highly Deviated Wells

• Multi-layered Reservoirs – Vertical Penetration

• Selective Acid Placement – Zonal Isolation – Depth Control

• Determination of Effectiveness • Removal of Spend Acid – The Solids and Fines in the Spend Acid will quickly Re-plug Perforations 07

Matrix Stimulation Methods • 15% HCL with Ball Sealers • Selective Acid Tool run on Tubing with a Service Rig • Acidizing through Coiled Tubing • Selective Acidizing through CT using Packers • Selective Acidizing through CT using Foam Diversion

08

Selective Acidizing through CT using Packers • Zonal Isolation – Straddles a predetermined interval. – Interval is variable using spacers. – Treatment is controlled by CT movement and Pump Pressure

• Depth Control – Use Tubing End Locators 09

Selective Acidizing through CT using Packers

Tubing End Locator

10

Selective Acidizing through CT using Packers • Considerations – Advantages • Leaves no diversion residues • No guessing where fluid is going • High Positive delta P in any given zone

– Disadvantages • • • •

Inflatables are consumable items Limited number of set/unsets Narrow specification envelope Not applicable in open hole or Gravel Pack Completions 11

Selective Acidizing through CT using Foam Diversion

• Zonal Isolation – Generation and maintenance of a stable viscous foam in the matrix of the “thief zone” – Permeability is temporary reduced and flow is diverted to the adjacent damaged zone. – 75’ Zones, depending on flow rates, porosity and behind pipe channels.

• Depth Control – Tubing End Locator

12

FoamMAT Diversion - Step 1 Damaged Zone

Thief Zone

1

Clean the Wellbore Area, by displacing oil or condensate 13

FoamMAT Diversion - Step 2 Damaged Zone

Thief Zone 1

2

Saturate the near wellbore with foamer

14

FoamMAT Diversion - Step 3 Thief Zone 11

Damaged Zone

2 2 3

Foam Injection : Foam bank is formed in both layers

15

FoamMAT Diversion - Step 4 Thief Zone 11

Damaged Zone

2 2 3 4

Shut In Period : Foam dissipates rapidly in damaged zone

16

FoamMAT Diversion - Step 5 Thief Zone 11

Damaged Zone

2 2 3

Inject Treating Fluid Containing Foamer : Acid preferentially flows into low perm layer. 17

Selective Acidizing through CT using Foam Diversion

• Considerations – Advantages • • • • •

Not sensitive to pressure fluctuations Non-damaging diverter system Single trip treatments Not temperature sensitive Improved clean up through energized treating fluids

– Disadvantages • Low rates, high pressures • Shut in period for foam stabilization 18

Monitoring & Control • Surface Data vs Downhole Data – Pressure • Surface pressure read outs have historically been used to monitor, control or evaluate Downhole events. • Pressure drop through CT, signal dampening, Nitrogen break out and response time are causes for in-accuracy

– Temperature • Surface Temperature read outs are not used.

– Depth • Surface measurements reflects the length of tubing lowered in the well. • End of tubing position is determined by well geometry, CT 19 stiffness, fluid environment and external forces

Downhole Sensor Package Plastic Coated Wireline

Cable Clamp/Check Valve

Mechanical Release Pressure/Temperature Gauge

20

Downhole Sensor Package CT with Plastic Coated Wireline

P, T Gauge

PC for Data Processing

Flow-by Housing

21

Monitoring & Control • Downhole data to control treatment – Interval determination • Standard Wireline Correlation techniques can be used to pin point a position in the well, providing the hole is cased and GR/CCL has been run before.

– On site Adjustments to Foam and Acid Volumes • Minimum Pressure response required before starting the initial acid stage

– Optimum Matrix rates below Frac Pressure • Limits can be set very close to maximum allowable BHP for optimum results 22

Evaluation • Downhole data to evaluate treatment – Foam Diversion Effectiviness • BHP and Tubing Movement Comparrisons are used to determinte the Foam Diversion Effectiviness

– Effectiviness of treatment on vertical conformance • BHP data in conjuction with pre and post job injection profiles 23

Case History 1 - Canada Well 1 Objective • Remove damage from plugged zones in horizontal water injector, while diverting away from prolific zones.

– Treatment • • • • •

Clean near well bore with Mutual Solvent Saturate the near well bore region with surfactant Inject 65 Quality Foam Shut in Inject 15% HCL with foaming agent

– Results • Treatment was successful in opening plugged zones, but efficient diverting was not accomplished along the total length of the well. Combined injection in the two main 24 zones decreased from 60% to 55% of the total fluid.

Case History 1 - Well 2 – Objective • Remove damage from plugged zones in horizontal water injector, while diverting away from prolific zones.

– Treatment • Foam diversion stages were increased in size to obtain better diversion. • Standard FoamMAT treatment was pumped

– Results • 5 plugged intervals are now taking injection • Treatment was successful in diverting away from zone which was taking 80% of injection before. Injection after treatment was less than 15% of total fluid. 27

Case History 2 - North Sea – Objective • Verify whether all perforations accept fluid during injection after a frac treatment

– Programme • Run in hole with CT and Downhole Sensor Package to Monitor temperature profiles pre and post fluid injection.

– Results • Temperature profile indicates a section of perforations is not accepting fluid. • Downhole Pressure Decline Data was generated after injection was stopped 30

Conclusions – Horizontal wellbores have successfully been acidized. – Proper diversion is possible without mechanical means. – Foam diversion has had positive impact on vertical conformance and injection gains. – Generating downhole date using CT E-line technology in an acid environment is feasible. – Real time downhole pressure and temperature data is important for interpretation of foam diversion effectiveness in horizontal wellbores. – A Downhole Sensor Package is an efficient means of evaluating perforations performance during pumping activities through Coiled Tubing. 33

General Gas & Liquid Well Kill Procedure 1)

Bull head kill fluid from surface A- mix and pump non-damaging viscous pill or bridging agent. B- follow the pill with kill fluid.

2)

Circulation kill assisted with C.T. A- place the end of the C.T. below the source of pressure. B- spot a bridging agent across the interval of the pressure source. C- circulate kill weight fluid to surface 1½ annular volume. D- S.I. the well for 30 min., break circulation while POOH.

Squeeze Cementing

Squeeze Cementing

• The process of forcing cement slurry through perforations, holes or leaks in the casing/liner to obtain an hydraulic seal

Squeeze Cementing Applications • Squeeze cementing treatments are commonly designed to resolve: – Water or gas channelling (primary cement job failure) – Injection water (or gas) break-through – Gas or water coning – Isolation of unwanted perforations – Losses to a thief zone or improved injection profile

Squeeze Cementing Advantages • Squeeze cementing operations performed through a CT string have several benefits/advantages: – Thru-tubing intervention – Integrated operations • e.g., fill removal, well kick-off

– Accurate slurry placement • “mobile” injection point

– Reduced contamination of small volume treatments – Time, product and cost savings - proven!

Laboratory Testing • Successful completion of a cement squeeze is dependent on achieving specific slurry/cement qualities. Extensive testing may be required for: – Thickening time • job time plus 40 to 50% recommended

– Fluid loss • optimised for filtercake build-up

– Rheology • optimised for ease of pumping and early gel strength

Thickening Time • Thickening time considerations for CT applications include: – Non standard API conditions • rate of temperature change • large surface area - use BHST not BHCT • greater mixing energy imparted

– Treatment time • quicker placement • longer time at BHT

– Early gel strength • treatment performed with CT string (and tools) in slurry

Fluid Loss High fluid loss resulting in bridging of wellbore

Cement filled perforation with good node profile

• Effects of fluid loss on cement node size

Low fluid loss resulting in ineffective node build up

Rheology • Most slurries behave as Bingham Plastics – Plastic viscosity • function of the solids contained within the slurry

– Yield point • assesses distribution of solids within the slurry

• Key requirements: – No settling of solids – Minimal early gel strength – Good stable slurries produce good (replicable) qualities

Job Design • Critical job design parameters include: – – – – – –

Slurry volume Slurry placement Depth correlation Protection against contamination Cement column stability Tool (nozzle selection)

Slurry Volume • Considerations for slurry volume include: – Length of interval and capacity of casing/liner – Presence of void areas behind perforations – Force on CT string • e.g., additional tension caused by string weight

– Configuration of mixing equipment and surface lines etc. – Ability or requirement to use of cement plugs, pigs or darts

Slurry Placement • Considerations for slurry placement include: – – – –

Depth control (including correlation) Contamination protection during placement Cement column stability Isolation of adjacent (untreated or sensitive) zones – Tubing movement (control and coordination)

Protection Against Contamination • Considerations for contamination protection include: – Protection becomes critical with small slurry volumes – Contamination results in unpredictable results • thickening time • fluid loss • rheology

– Cleanliness of mixing equipment – Optimized rig up (especially mixing equipment) – Mechanical separation

Reel Manifold Sampling Point CT string

From pump

To disposal

Sample point

• Reel manifold sampling point (typical)

Cement Column Stability

Slurry settles on platform Slurry “ropes” and contaminates Sand plug

• Effect of stable platform

Tool Selection

Small circulation ports for efficient placement

Large circulation ports for efficient reverse circulation

• Cement nozzle (example)

Squeeze Cementing - Typical Rig-up Sample point

Squeeze manifold

Cement Choke manifold

Water Displaceme nt fluid

Sample point

Typical cement equipment configuration

Treatment Execution • Execution of squeeze cementing operations is accomplished in four basic steps: – – – –

Wellbore preparation Slurry mixing and pumping Cement squeeze Removal of excess cement

Wellbore Prep - Slurry Placement Filtered seawater (or similar)

Slurry pumped at maximum rate

Choke - open

Choke - open

Pack fluid Spacer Nozzle 50 ft below interface

Slurry Wellbore clean and packed

Preparing the wellbore

Placing the cement slurry

Slurry Squeeze Low rate continuous or hesitation squeeze

Slurry pumped at maximum rate

Choke controlled

Choke closed if wellbore is packed

Nozzle 50 ft above interface

Pack fluid Pack fluid Slurry

Nozzle above thief zone

Spacer Slurry

Pack fluid

Placing thixotropic slurry (alternative)

Commencing the squeeze

Removing Excess Slurry Contaminant pumped at maximum rate

Pack fluid pumped at maximum rate

Choke controlled

Choke controlled to maintain squeeze pressure

Nozzle moved continuousl y

Pack fluid Slurry

Pack fluid

Contaminated slurry

Nozzle penetrates to mix 50:50

Slurry

Completing the squeeze

Contaminating excess cement

Removing Excess Slurry Pack fluid pumped at maximum rate/pressure (1500psi)

Open returns

Slurry pumped at maximum rate

Choke controlled

Pack fluid Pack fluid

Nozzle reciprocated across treatment area Back pressure maintained

Nozzle penetrates to mix 50:50

Contaminated slurry

Reverse circulating contaminated slurry

Commencing the squeeze

Evaluation of Squeeze • Evaluation method dependent on specific conditions, options may include: – Pressure testing wellbore – Inflow test – Production characteristics • GOR, WOR

• Additional checks for: – Wellbore access • access past squeezed zone • access to rat hole

COILED TUBING DRILLING Advantages of CTD Key advantages of CTD techniques and equipment include: Safety fewer personnel, reduced pipe handling Economic lower mobilisation cost, slimhole technology Operational underbalanced drilling, thru-tubing re-entry Environmental smaller footprint, reduced noise and emissions

Limitations or Disadvantages •Limitations or disadvantages of CTD techniques and equipment include: – Economic • new technology in a cost conscious market

– Hole size • limitations of slimhole

– Rotation • inability to rotate string

– CT fatigue and life • confidence in life prediction

CTD Applications Well Status Reentry

•CTD applications can be classified by: – Well status – Well preparation – Wellbore trajectory – Wellbore conditions

New well

Well Preparation Tubing or completion removed

Thru-tubing operation

Wellbore Trajectory Deepening

Side-track

Wellbore Conditions Underbalanced Drilling

Overbalanced Drilling

Underbalanced Drilling •Definition: Drilling while maintaining the equivalent circulating density of the wellbore fluid less than reservoir pressure, I.e..., the well is capable of flowing reservoir fluid while tripping and drilling.

Underbalanced Drilling •Advantages: – Reduced formation impairment from fluid invasion – Improved penetration rates •Disadvantages: – Borehole stability – Fluid/pressure management requirements – A technique against conventional thinking!

Creating Underbalanced Conditions •The means of creating underbalanced conditions depend on specific reservoir conditions: – Reservoir pressure above water column hydrostatic pressure • use low density fluids while closely monitoring the equivalent circulating density

Creating Underbalanced Conditions • The means of creating underbalanced conditions depend on specific reservoir conditions: – Reservoir pressure below water column hydrostatic pressure • use very low density fluid (foam) • annular gas lift • kick-off well and use appropriate pumping/fluid schedule

Drilling Fluid •Drilling fluids in underbalanced applications differ from conventional overbalance: – Not required to balance the formation pressure – Formation compatibility not so critical

•However fluids should: – Efficiently transport cuttings from the wellbore – Cool and lubricate the bit – Control corrosion – Provide sufficient inhibition over shale

Surface Equipment •Surface equipment for CTD operations: – CT substructure or rig – CT equipment – Well control equipment – Pumping equipment – Mud storage and treatment equipment – Pipe handling equipment – Ancillary surface equipment – Monitoring and recording equipment – Safety and emergency equipment – Rig camp and wellsite facilities

CTD Substructures and Jack Systems

•CT and pipe jack substructure - pipe jack mode

Pressure Control Rigup

Mud cross - manual valve Annular BOP - manual valve

Mud cross - choke line (manual and remote valve)

Mud cross - kill line

•Hole size up to 4-in. (with annular)

Downhole Equipment •Downhole equipment for CTD operations: – Bits – Downhole motors – Downhole CT equipment – BHA for vertical well or well deepening – Directional drilling BHA – Special BHA components – Fishing tools

Bits •Bit selection is made after considering: – Formation type, hardness and abrasiveness – Motor speed (RPM) and torque characteristics – Available WOB – Drilling fluid type and available flow rate

•Two basic types of bit are used in CTD applications: – Rock bits – Drag bits

Downhole Motors •Three basic categories of motor for CTD applications: – Vane motors • Volker Stevin

– Turbines • Neyrfor Weir

– Positive displacement motors (PDM) • Anadril, Drilex, Slimdril etc.,

Positive Displacement Motors •PDM specifications relate to: – Outside diameter (OD) • determines flowrate required and torque output

– Number of stages (lobes) • determines speed and torque

– Operating flowrate • ability to operate efficiently within a range of flow rates

CTD Downhole Equipment •Downhole equipment for CTD operations: – CT connectors • dimple/grub screw type preferred

– Disconnecting subs • incorporated into CTD drilling head

– Check valves • incorporated into CTD drilling head

BHA for Vertical Wellbores CT string

+/- 3ft

CT connector

Hole size

Collar OD

Check valves

(in.) >6 3-3/4 to 4-3/4 < 3-7/8

(in.) 4-3/4 3-1/8 2-7/8

Release joint

WOB

+/- 10ft

Drill collar(s)

Motor

Bit

BHA for Deviated Wellbores CT string

CT connector

+/- 3 ft

Check valves Release joint

+/- 10 ft

Orienting tool

+/- 30 ft

Nonmagnetic housing

+/- 10 ft

Motor

Bit

Components of a Directional BHA •Directional BHAs are assembled from several key components or subsystems, for example: – MWD tool/system – Wireline steering tool – Monel - non magnetic drill collar – Orienting tool – Pump actuated oriented tools – Electrically operated orienting tools

Some of Down Hole Tool

FISHING GRAB • • • • •

Features/Benefits Flow through facility Simple flexible design Robust construction External fish neck available

FLOW ACTIVATED ALLIGATOR GRAB

Features/Benefits Variable grab lengths available Optional external fishneck

FLOW ACTIVATED RELEASABLE FISHING/BULLDOG SPEAR • • • • •

Features/Benefits Flow or drop ball activated Hardened & double tempered slips Robust construction Variable slip sizes for each tool

FLOW ACTIVATED RELEASABLE OVERSHOT • • • • • •

Features/Benefits Internal hammer action assists release Flow or drop ball activated Hardened & double tempered slips Robust construction Variable slips sizes for each tool

Common DO’s & DON’T DO Rig up and pressure test equipment as per the recommended guidelines. Request that the service vendor provide a flow tee to direct the returns flow out of the borehole. Place the flow tee directly below the well control stack. Install an adjustable choke on the returns line and have a replacement stem available on location. Verify the calibration of the choke with documentation provided. Rig-up full bore pipe tee’s and bull plugs on all “hard-90°” turns in the returns line. This will prevent erosion of the pipe by the sand laden returns. Be prepared for wash fluid losses to the formation and make provisions for addition wash fluid to be available on location.

• Tankage on location should should be sufficient to capture all returns and solids removed from the well. Plan to have the liquids treated through the production facilititeies or sent to an approved disposal site. Solids should be cleaned and dumped, or sent to the proper disposal site. • Run into the borehole with the coiled tubing at an injection rate no faster than 30-40- feet per minute if the top of sand is unknown. If the top of fill has been located in the borehole, run-in rates should not exceed 60-90 feet per minute. • Maintain returns throughout the wash program! If the observed returns decrease or cease, pull up the hole with the coiled tubing until returns are reestablished. • TAKE YOUR TIME WHEN WASHING SOILDS OUT OF THE WELL!!! When breaking through solids bridge s, allow sufficient time to circulate solids out of the hole before continuing downhole.

• Check tubing drag every 1000’-1200’. Also, keep the coiled tubing moving during the wash program to prevent sticking in the solids laden returns. • Monitor the surface pump pressures and returns choke pressures (if used) when circulating up slugs of solids-laden fluid. • When the bottom of the desired wash section is reached, circulate a minimum of two annular volumes up the borehole prior to extracting the coiled tubing from the well.

DON’T

• Do not allow the coiled tubing to remain stationary for a period of time longer than 25% of the bottoms-up circulation time when transportation solids up the annulus. • Do not shut down pumps for any reason, unless you are out of the borehole. Wells circulate clean can have sand accumulated up the hole which can have sand accumulated up the hole which can fall back when circulation is interrupted.

DON’T • Do not ignore the pump pressure requirements for accommodating increases in hydrostatic pressure and frictional pressure losses generated during the solids wash portion of the program. If washing large slugs of sand, the annular frictional pressure losses and increases in “dirty” fluids density will cause surface pump pressures to increase accordingly. • Do not wash out of production tubing into casing without circulation at least one tubing volume (at depth) up the annulus.

Back up slides

Tool Deployment Systems

Deployment Systems • Required to enable safe deployment and retrieval of long tool strings in live wells. Basic requirements include: – Provide necessary test and check facilities • e.g., provision for pressure testing before RIH

– Provide necessary contingency options • e.g., annular seal redundancy

– Provide necessary pressure/fluid barriers • e.g., North Sea requirement for two barriers at all times

– Minimize exposure of personnel to risk • e.g., fall or suspended load hazards

Evolution of Safe Deployment • Deployment systems have evolved to meet necessary operational and safety requirements – Tower or Structure – Conventional lubricator deployment • adapted from wireline techniques

– Tool deployment system • First system to reduce working height

– Safe tool deployment • Incorporated operational and safety features

– CIRP • Special system developed for perforating operations

Lubricator Deployment Injector head Stripper

Assembled height up to 60ft

Wireline lubricator

Quad BOP

Wellhead connection Lubricator deployment - equipment configuration

Tower Deployment

Lubricator Deployment • Advantages – System utilizes “conventional” equipment and tools

• Disadvantages – A large crane (capacity and height) is required to support the injector head - dependence on crane operator – Operator visibility of all CT and pressure control components is severely limited – Injector head access is restricted – Personnel are exposed to suspended loads during the rig up procedure

Tool Deployment System -1 Sheeve wheel and stuffing box

Toolstring passing through lubricator Wireline lubricator

Blind rams Shear rams Quad BOP

Slip rams Pipe rams

Wellhead connection

Installing the toolstring

Tool Deployment System - 2 Lubricator removed leaving deployment bar exposed Lubricator removed

Blind rams Quad BOP Wellhead connection

Hanging off the toolstring

Shear rams Slip rams Pipe rams

Tool Deployment System - 3 Injector head assembly lifted and connected to lower pressure control assembly

Tool connection made

Blind rams Quad BOP

Shear rams Slip rams

Wellhead connection

Pipe rams

Connecting the toolstring and running string

Tool Deployment System - 4 Injector assembly and pressure control stack connected and tested

Lubricator riser connection made and tested

Blind rams Shear rams

Quad BOP Slip rams Wellhead connection

Running the toolstring

Pipe rams

Tool Deployment System - 5 • Advantages – Enables reduced height working for injector head – Requires minimal special equipment

• Disadvantages – There is a high dependency on crane operator skills during crucial stages of the operation – Injector head weight must be “stabilized” to enable tool connection – Operators are still exposed to suspended loads during the rig-up and rig-down periods

Safe Deployment System Components Hydraulic supply and return

All system functions controlled from central control panel

Injector head Stripper 1 2 3 4a 4b 5 6 7 8 9 -

QL Open QL Close Pressure Return ABOP Return Stripper SDDT Close SDDT Open ABOP Close ABOP Open

Hydraulic Control Panel

Short riser Quick latch Side door deployment tool

Annular BOP Quad BOP Wellhead connection

System components

Safe Deployment System - 1 Toolstring run/assembled using lubricator and wireline deployment techniques

Tools run through system to place deployment bar within BOP

Quick latch

SDDT Annular BOP

Blind rams Shear rams Slip rams

Quad BOP

Pipe rams Wellhead connection

Installing the toolstring

Safe Deployment System - 2 Lubricator removed at quick latch for second tool stage Quick latch

Running string removed from deployment bar

SDDT Annular BOP Quad BOP

Blind rams Shear rams Slip rams

Wellhead connection

Hanging off the toolstring

Pipe rams

Safe Deployment System - 3 Injector head assembly connected to lower pressure control stack

Second tool stage connected to deployment bar

Quick latch

Blind rams Annular BOP

Shear rams Slip rams

Wellhead connection

Pipe rams

Connecting the running string and toolstring

Safe Deployment System - 4

Swivel connection to enable connection to be made up without rotating assemblies Guide tool to enable safe and easy stabbing to connections

Guide tool and swivel connector

Safe Deployment System - 5 Window closed

Injector head assembly connected to lower pressure control stack, window closed and assembly tested

Annular BOP

Blind rams Shear rams Slip rams

Wellhead connection

Running the toolstring

Pipe rams

Safe Deployment System - 6 Wireline PEH - E head AH - 38 adapter Wireline adapter with landing collar for guide tool location

Conductor deployment bar assembly

Balance housing Spacer (for ABOP)

Turndown section (for pipe and slip rams)

Tool string

Safe deployment system toolstring

Safe Deployment System - 7 • Advantages – Minimum operator exposure to suspended loads – Positive position indication for tools in running equipment – Improved redundancy/contingency options – Dual pressure barriers in place throughout operation – Greater stability during running/connection procedure

• Disadvantages

CIRP Deployment System

Conveying Guns on CT • Life well perforating – Retrieval of long tool strings without killing the well.

• Highly deviated and horizontal holes • Complex wellbore paths – Corkscrewed tubing – Dog legs

• Long and heavy gun strings • HPHT wells – Need for simple and reliable systems (CBF-AA Head)

CIRP System • CIRP: Completion Insertion and Retrieval of long gun strings under Pressure – Enables safe deployment of long perforating gun strings • satisfies special requirements for explosives handling

– Eliminates requirement for rat hole to drop guns • spent gun string retrieved

– Enables long intervals to be perforated with controlled underbalance • advantage over multiple runs

– Avoids necessity for well kill and associated damage • perforating through the completion (thru-tubing)

Conventional CT Equipment Configuration

Injector head Stripper (dual) Quick latch Quad BOP

Shear/seal BOP

Wellhead

Equipment configuration (general) for conventional CT operations

CIRP CT Equipment Configuration Injector head and stripper assembly above quad BOP

Quick latch Gate valve Quad BOP adapted for CIRP system

Shear/seal BOP on wellhead

Typical equipment configuration for CIRP operations

Conveying Guns - CIRP System •

• •

CT Connector

Firing Head

Features – Pressure activated firing mechanism – Surface Deployment System Advantages – Any lenght of guns Dis-advantages – Depth Correlation

CIRP Connectors

Guns

CIRP - Toolstring Components - 1 Pinion teeth

Deployment Stinger

Sleeve

Deployment connection Fork sub Latch spring

Deployment Receiver

CIRP - Toolstring Components - 2

Before firing

CBF firing head components

After firing

CIRP - BOP Ram Components

CIRP BOP with toolstring in place

CIRP system components

CIRP System Sequence - 1 Wireline conveyed toolstring Inner Ram - OPEN Outer Ram - OPEN

Inner Ram - OPEN Outer Ram - OPEN

Run in to position the slick joint

CIRP System Sequence - 2 Inner Ram - OPEN Outer Ram - OPEN

Inner Ram - OPEN Outer Ram - CLOSED

Close no-go rams and set down tool weight

CIRP System Sequence - 3 Inner Ram - OPEN Outer Ram - OPEN

Inner Ram - CLOSED Outer Ram - CLOSED

Close locks and perform pull test

CIRP System Sequence - 4 Inner Ram - CLOSED Outer Ram - CLOSED

Inner Ram - CLOSED Outer Ram - CLOSED

Close guide rams and engage rack to disconnect running tool

CIRP System Sequence - 5 Inner Ram - CLOSED Outer Ram - CLOSED

Inner Ram - CLOSED Outer Ram - CLOSED

Run in with next tool section

CIRP System Sequence - 6 Inner Ram - OPEN Outer Ram - CLOSED

Inner Ram - CLOSED Outer Ram - CLOSED

Stab male stinger, open rack and pull test connector

CIRP System Sequence - 7 Inner Ram - OPEN Outer Ram - OPEN

Inner Ram - OPEN Outer Ram - OPEN

Open guide rams, locks and no-go rams and RIH

CIRP System Specification •CIRP connector specifications (includes Safecon and sealed balistic transfer components:

•

Outside diameter (in.)

• • • • • • •

Effective BOP spacing (in.) 11.5 11.5 Tensile strength (000 lbf) 147 200 Guns size (OD - in.) 2-7/8, 3-3/8, 3-1/2 4-1/2, 7 Explosive HNS HNS Pressure (000 psi) 25 25 Temperature (OF) 400 400 BOP size/type 4.06 quad/combi 5.125 custom

3.0

4.5

CIRP Case Histories - Q1 1997 Job No.

Dowell Unit

No.of Conveyance Gun Total No. of Wellbore Surface Runs Method Size Length Connectors Deviation Pressure (ft) per Run (psi)

1 2 3

EAF NSR NSR

1 10 2

CT-TCP WL CT-TCP

2-7/8 900 3-3/8 1200 2-7/8 721

23 2 11

90o 60o 18o

2000 200 1100

4 5 6

EAF NSR MEA

1 1 1

CT-TCP CT-TCP CT-TCP

2-7/8 3-3/8 2-7/8

870 197 50

21 5 2

82o 29o 90o

1900 500 100

7

NSR

4

CT-TCP

2-7/8 1235

14

90

3000

Job 4 - CT connector released unintentionally. Job 6 - Severe dogleg limted gun length. Job 7 - 44 connectors with 1 trigger charge failure

CIRP Operational Issues • CIRP operation issues identified in early experience include: – System is technique sensitive • training/education essential • good coordination of operating personnel essential

– Contingencies must be well planned and understood • potential for complex pressure control conditions

– Areas of responsibility • for explosives, guns and connections • operation of pressure control equipment • operation of deployment equipment

CoilCADE

Computer Aided Design and Planning for Coiled Tubing Operations

Job Design Objectives • Job Feasibility – Penetration and Forces – Circulation and Solids Transport

• Conform to Minimum Safety Standards - SLP 22 – Operating Envelope – Safety Margins for Pressure, Tension, Ovality and Fatigue

• Equipment & Material Requirements – Tubing Wall thickness and length – Pump and tank sizes – Fluid, additives and Nitrogen

Feasibility Tubing Forces Model

• Principal functions: – Stress and Reach : Confirm the selected toolstring can be run to the specified depth within applicable operating limits – Downhole Force : Confirm the availability of force (push/pull) for BHA operation – Doglegs : Verify toolstring will pass within the wellbore profile and geometry – Predict weight indicator readings Vs. depth for RIH and POOH

CT Limitations One Dimension Vs Two Dimensional Mat. Spec. Values

Neutral

Axial Stress

Radial Stress

Combination

Combination

Pressure & Tension Limits • Effects of pressure and tension are closely related (cumulative forces) consequently operating limits should consider both factors • For example, increasing tension: – Lowers collapse resistance – Increases burst resistance

Pressure, tension and bending

Pressure and bending

Tension and compression

Pressure, tension and possible torque

CT Limitations

Burst Burst

Tensile Compression Compression Collapse

Tensile Collapse