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Well intervention encompasses the range of operations performed on a well after initial construction and throughout its producing life — from completion and stimulation through remediation and, ultimately, plug and abandonment. Interventions are most often performed to restore or enhance production on mature wells, evaluate downhole conditions, or repair wellbore and completion integrity.

Interventions are conveyed by several methods, each suited to different objectives: workover (pulling) rigs for jointed-pipe operations requiring full completion retrieval; wireline (e-line and slickline) for gravity-conveyed logging, perforating, and plug setting; hydraulic workover/snubbing units for heavy live-well tubular work; and coiled tubing units for pumping-intensive and horizontal-well work.

Coiled tubing offers the broadest single-conveyance capability because it combines continuous circulation, live-well deployment, and the ability to push tools into horizontal laterals. Representative CT interventions include wellbore cleanouts, plug millout, acidizing and matrix stimulation, annular fracturing, remedial cementing and squeezes, CT-conveyed logging, fishing, nitrogen lifting/kickoff, and CT drilling.

Coiled tubing (CT) is a continuously milled string of high-strength, low-alloy steel pipe, manufactured without threaded connections and spooled onto a reel for transport and deployment. Because the string is continuous, it can be run into and out of a live (pressurized) well through a stripper and BOP stack while fluids or nitrogen are circulated — the defining capability that distinguishes CT from jointed-pipe conveyance.

CT is manufactured in outside diameters from approximately 0.75 in. to 5.25 in.; sizes from 2 in. to 2-7/8 in. dominate onshore intervention work in North America. Strings are deployed from a coiled tubing unit in well completion, intervention, workover, and drilling applications, both onshore and offshore.

Coiled tubing drilling (CTD) is a drilling method that uses a continuously milled CT string in place of jointed drill pipe, with bit rotation supplied by a downhole positive displacement motor rather than surface rotation. The string is typically equipped with an internal e-line for real-time directional telemetry and control of the steerable BHA in deviated and horizontal sections. While a niche application in the United States, CTD is well established in the Middle East and parts of Canada, particularly for underbalanced re-entries and wells suited to open-hole (barefoot) completion.

Key advantages of CTD:

• Reduced footprint and cost. A CT drilling spread requires less location area and a smaller crew than a conventional rig, and continuous pipe eliminates connection time — significantly reducing trip times from surface to TD.
• Improved safety. Eliminating surface pipe handling and connection make-up removes personnel from red-zone exposure at the well center.
• Underbalanced drilling (UBD) capability. Drilling with bottomhole pressure below reservoir pressure avoids kill-weight fluids, minimizing invasive formation damage and preserving near-wellbore permeability.
• Production while drilling. Underbalanced operation allows the well to flow during drilling, giving operators real-time reservoir characterization. Productivity data acquired while drilling supports geosteering decisions, lateral extension or termination, and early first production.

Coiled tubing service companies perform well interventions on behalf of exploration and production (E&P) operators. The application range spans plug millout, wellbore cleanouts, jetting, acidizing and stimulation, remedial cementing, nitrogen lifting, annular fracturing, fishing, logging, and CT drilling.

CT crews work across the full spectrum of wellhead pressures and formation types, from low-pressure conventional wells to high-pressure unconventional shale completions. Relative to conventional workover rigs, CT units rig up faster, occupy a smaller footprint, operate on live wells without killing the well, and complete most interventions in less time — generally delivering a lower total cost of intervention.

Continuous spooled steel pipe traces its origin to Operation PLUTO (Pipeline Under The Ocean) during the Second World War, in which continuous welded pipelines were unreeled across the English Channel to supply fuel to Allied forces following the Normandy invasion. The technology was adapted to oilfield well servicing in the early 1960s, when the first coiled tubing units were developed for washing sand from wellbores, and has since evolved through advances in metallurgy, tube milling, fatigue modeling, and injector design into the modern intervention and drilling conveyance used worldwide.

Coiled Tubing strings are made from multiple flat cuts of hot rolled sheet steel, called master coils. These master coils are then placed into a mill that turns the flat sheet into a continuous rolled tube. From there, the rolled tube is formed into a long continuous steel pipe with lengths that can go for miles.

CT manufacturing begins with hot-rolled, high-strength low-alloy sheet steel supplied as master coils. The master coils are slit into strips of the required width, and successive strips are joined end-to-end with angled bias (skelp-end) welds to build the continuous length — including transitions between wall thicknesses in tapered strings. The joined strip is fed through a tube mill, where it is progressively roll-formed into a round profile and closed with a continuous longitudinal seam weld (high-frequency induction), then sized to final O.D.

In-line inspection during milling includes eddy current testing of the seam and body, laser micrometry for O.D. verification, and ultrasonic wall thickness measurement, all data-logged against string position. After milling, the string is spooled and subjected to qualification testing per API 5ST — tensile testing, flattening and flaring tests, hardness testing, and metallographic examination of weld samples — followed by a full-length hydrostatic test. Finally, the string is purged of test fluid, dosed with corrosion inhibitor, and spooled onto the service reel or shipping spool ready for operations.

Only a small number of coiled tubing manufacturers operate in the United States; Global Tubing, with its manufacturing facility in Dayton, Texas, is one of them. Global Tubing produces CT in outside diameters from 0.750 in. (19.1 mm) to 5.000 in. (127 mm) and wall thicknesses from 0.087 in. (2.2 mm) to 0.337 in. (8.6 mm), supported by proprietary steel chemistry, in-house mill technology, and digital process control. Service locations include:

1. Dayton, Texas, USA (manufacturing facility and service center headquarters)
2. Midland, Texas, USA (service center)
3. Red Deer, Alberta, Canada (service center)

1. Coiled Tubing Unit (CTU) — The complete surface spread: control cabin, reel and CT string, injector head and gooseneck, power pack, and the well control stack (stripper and BOPs).
2. Coiled Tubing Reel — The drum that stores and deploys the string, fitted with a levelwind for even spooling and a rotating swivel enabling circulation while the reel turns. Skid- or trailer-mounted, and manifolded to fluid and/or nitrogen pumps. The reel motor maintains back-tension against the injector at all times.
3. Power Pack — The hydraulic power unit (HPU) — diesel-hydraulic or electric-over-hydraulic — supplying pressure and flow to the injector, reel, BOP accumulator functions, and cabin controls.
4. Control Cabin — The operator console, positioned with line-of-sight to the injector and reel (or as a standalone module offshore). Houses injector, reel, stripper, and BOP controls plus instrumentation: weight indicator, depth counter, wellhead and circulating pressure gauges, and data acquisition.
5. Injector Head — The traction unit that grips the string between opposed gripper-block chains, controlling RIH/POOH direction and speed, providing pulling capacity and snub force against wellhead pressure. Operated from the cabin via a closed-loop hydraulic system.
6. Gooseneck (Tubing Guide Arch) — Mounted atop the injector, guiding the string from the reel into the chains at a controlled bend radius — a key fatigue parameter.
7. Blowout Preventers (BOPs) — The secondary well control barrier:

1. Quad BOP — four ram cavities: blind, shear, slip, and pipe rams (top to bottom).
2. Combi BOP — two cavities combining blind/shear rams and pipe/slip rams, common where stack height is limited.

10. Stripper (Stripper Packer) — The primary barrier: hydraulically energized elastomer elements maintaining a dynamic seal on the moving string. (Side-door and tandem configurations are common; tandem strippers provide element redundancy on sour or high-pressure work.)
11. Fluid Pumps — Positive displacement (typically triplex plunger) pumps, usually rigged in tandem, delivering treatment or circulating fluid to the reel inlet.
12. Nitrogen Pumps — Cryogenic nitrogen converters supplying gaseous N₂ for lifting, energized (commingled) fluids, underbalanced operations, and purging the string dry.
13. Crane / Mast — Supports the injector and riser assembly over the wellhead; conventionally a third-party crane, though self-supporting mast and tower CT units eliminate the crane requirement.
14. Flowback Equipment — Chokes, manifolds, separators, and tanks connected to the production tree wing valve to handle returns and control backpressure (effective wellhead pressure) during the operation.

1. Live-well capability. CT deploys through pressure control equipment, so the well does not need to be killed. Circulation can be maintained continuously in a balanced, barrel-in/barrel-out mode — avoiding both the formation damage and the deferred production associated with kill operations.
2. Minimized formation damage. No kill-weight fluids are placed against the formation, preserving near-wellbore permeability.
3. Mobility. CT rig-up and rig-down are typically completed within a day, versus multiple days for a conventional workover rig.
4. Speed. Continuous pipe eliminates connection make-up and break-out, drastically reducing trip time.
5. Safety. Reduced manual pipe handling removes personnel from dropped-object and pinch-point exposure at the well center.
6. Cost. Higher operational efficiency and shorter job duration reduce total intervention cost per well.

• Plug millout / drillout
• Wellbore cleanout (sand, proppant, scale, paraffin)
• Nitrogen lifting / well kickoff
• Remedial cementing and squeezes
• Annular fracturing
• Zonal isolation / sand control
• Tubing-conveyed perforating (TCP)
• CT-conveyed logging (production, integrity, and cased-hole)
• Acidizing and matrix stimulation
• Fishing and wellbore remediation
• CT drilling and underbalanced re-entry
• Velocity strings and capillary/chemical injection*

Unlike jointed tubulars, CT is intentionally worked beyond its elastic limit every cycle: each trip plastically bends and straightens the string at the reel, gooseneck, and injector chains. Cumulative low-cycle fatigue — accelerated by internal pressure during cycling — is therefore the primary life-limiting mechanism and is tracked segment-by-segment using fatigue modeling software fed by job data (pressures, running speeds, depths cycled).

String retirement is governed by fatigue-life consumption together with measured condition criteria: remaining wall thickness (UT), diameter growth/ballooning, ovality, mechanical damage, and corrosion. Prudent string management practices include rotating the working end via periodic cut-offs, re-heading after weak-point events, cycling at reduced internal pressure where the program allows, and full-length inspection between deployments.

Coiled tubing is manufactured to API Specification 5ST, which defines grades by specified minimum yield strength — CT70 through CT110 (70,000–110,000 psi), with CT80–CT100 most common in intervention service. Grade selection balances tensile and pressure capacity against fatigue ductility and, in sour wells, the hardness limits of NACE MR0175/ISO 15156.

Typical North American intervention strings run 2 in. to 2-7/8 in. O.D. to balance stiffness (reach), circulating rate, weight, and surface handling limits, with tapered wall designs from roughly 0.125 in. to 0.250 in. Larger O.D. (up to 3.5 in.+) supports high-rate cleanouts and extended reach laterals; smaller O.D. serves capillary, velocity string, and thru-tubing niches.

Live-well CT operations follow a two-barrier philosophy: at least two independent, tested barriers between reservoir pressure and atmosphere at all times. The stripper element provides the primary, normally closed dynamic barrier around the moving string; the BOP stack provides the secondary barrier, with slip/pipe rams to secure and seal on the string and shear/blind rams for ultimate shut-in. The internal string barrier is completed by dual flapper check valves in the BHA, preventing flow up the coil.

Pre-job well control planning covers stack-up pressure ratings versus maximum anticipated wellhead pressure, pipe-light/pipe-heavy force balance, kick detection and shut-in procedures, and function/pressure testing of all PCE on rig-up.

A balanced view of CT includes its constraints: reach in long laterals is bounded by helical buckling and lockup; circulating rates are limited by small internal diameter and high friction pressures; the string cannot be rotated from surface, so torque-dependent operations rely entirely on downhole motors; fatigue life is finite and strings are consumable assets; and maximum overpull is limited relative to jointed pipe, constraining heavy fishing loads. Extended reach tools, friction reducers, tapered string design, and larger-diameter coil each mitigate — but do not eliminate — these limits.

SMARTaper™ — Global Tubing’s patented tapered-string technology that eliminates bias-weld fatigue spikes for longer usable running length, increasing horizontal reach and adding strength in high-fatigue zones while managing overall string weight.

DURACOIL — Technically advanced, cost-efficient coiled tubing engineered for demanding downhole environments, with demonstrated improvements in fatigue life and predictability, abrasion resistance, and high-pressure performance.

Industry trends — As measured depths and lateral lengths grow, string designs become more complex: heavier tapers, higher grades, and larger O.D. for reach and rate. Parallel advancements in BHA technology (agitators and extended reach tools that mitigate helical buckling), friction-reducing chemistry, e-coil telemetry and real-time downhole measurement, and digital fatigue/tubing-forces modeling continue to expand the CT operating envelope.