How is coiled tubing used in plug and abandonment operations?

I. High-level purpose and where it fits in the value chain

Coiled tubing (CT) in plug and abandonment (P&A) is a rig or rigless conveyance method to clean, access, and place permanent well barriers (cement/mechanical), verify integrity, and prepare the well for final isolation and removal. It resides at the end of the upstream value chain—decommissioning—minimizing rig time, ensuring barrier quality, and reducing environmental risk.

• I.1 CT enables targeted barrier placement (inside casing and behind casing) with precise depth control and circulation, improving barrier quality.
• I.2 CT supports rigless P&A on platforms and land wells, and complements rig-based campaigns offshore to reduce critical path time.
• I.3 Typical CT roles in P&A: near-wellbore remediation, debris/scale removal, perforate–wash–cement behind casing, set mechanical plugs, mill/jet to access annuli, spot cement plugs, verify by tagging/pressure testing, and displace wellbore for final fluids.

II. Step-by-step process flow (how CT is used)

II.A. Planning and well control setup

• II.1 Engineering and modeling: define required barriers (depths/lengths), CT reach, hydraulics, equivalent circulating density (ECD), annular velocities, cement volumes/excess, contingencies (losses, stuck pipe).
• II.2 Rig-up PCE: install CT injector, stripper, CT BOP stack, and well control manifold; function test; pressure test to required limits.
• II.3 Kill and condition well: establish circulation; pump kill-weight brine/mud; verify static underbalanced/overbalanced strategy per reservoir state.

II.B. Wellbore preparation (CT cleanout and access)

• II.4 Cleanout to depth: run CT with bit, jetting nozzle, or motor/mill to remove sand, scale, cement, or collapsed debris; confirm full-bore access to target zones.
• II.5 Tubing/annulus access: if required, CT deploys abrasive jet cutters or mills to create windows/slots or perforate casing for annular communication ahead of behind-casing cementing.

II.C. Barrier creation inside casing

• II.6 Balanced cement plug placement: spot base fluid/spacer, pump tail/lead slurry via CT stinger, balance with calculated displacement, and pull CT slowly to avoid channeling; wait on cement (WOC), then tag and pressure test.
• II.7 CT-deployed mechanical plug: set retrievable/temporary bridge plug or permanent device using CT-conveyed setting tool; pressure test; cement on top if required to create dual barrier.

II.D. Annular barrier behind casing (perforate–wash–cement)

• II.8 Establish annular access: CT conveys abrasive jetting tool to cut 360° perforation clusters across the barrier interval.
• II.9 Wash/clean annulus: pump viscous sweeps/solvents via CT through a wash tool or straddle packer to remove mud/cake/degraded cement from the annulus until clean returns.
• II.10 Cement annulus: place cement via CT into the annulus, often through a straddle/inflatable packer for zonal confinement; verify tops of cement (TOC) via returns volume, temperature, or subsequent tagging.

II.E. Special CT tasks during P&A

• II.11 Caprock/liner top remediation: CT mills or jets to expose competent formation, then places a formation-to-formation cement barrier.
• II.12 Scale/paraffin removal and chemical placement: CT delivers dissolvers, acids, or chelants to ensure clean bonding surfaces for cement.
• II.13 Nitrogen lifting/displacement: CT bullheads N₂ or light fluids to achieve circulation or unload fluids prior to cementing or verification steps.
• II.14 Verification: CT tags top of cement, performs inflow/pressure tests via CT BHA valves, and acquires memory logs (e.g., CCL/gamma) to confirm locations.

II.F. Final placement and well handover

• II.15 Surface and environmental plugs: CT spots shallow plugs and cement at surface casing shoe or cellar as specified; displaces to benign fluids.
• II.16 Rig-down and reporting: bleed-off, pressure test PCE, rig down, and document barrier depths/lengths, test results, slurry designs, and volumes for regulatory closeout.

III. Major equipment/components and functions

• III.1 Coiled tubing unit: reel (stores CT), injector head (push/pull with constant tension), gooseneck (guides CT), control cabin (operates pumps and injector).
• III.2 Pressure control equipment (PCE): stripper/packoff, CT BOPs (ram/pipe shear), lubricator, quick-test subs; provides well control during live interventions.
• III.3 Pumping and mixing: high-pressure pumps, cementing unit, batch mixers, densitometers; enables accurate slurry and spacer placement.
• III.4 Downhole BHA: jetting nozzles, wash tools, mills/motors, underreamers, abrasive cutters, inflatable/straddle packers, setting tools for mechanical plugs, non-return/check valves, memory gauges (pressure/temperature), CCL/gamma.
• III.5 Fluids and additives: spacers, viscous sweeps, LCM, cement slurries (lead/tail), solvents/acids, nitrified fluids, nitrogen units for lifting.
• III.6 Surface well control: choke manifold, flare/vent lines, kill lines, returns handling and filtration for debris control.
• III.7 Measurement: weight indicator, depth tracking with CCL correlation, surface density/flow meters; optional downhole pressure memory for ECD/TOC assessment.

IV. Key performance drivers (efficiency, cost, safety, emissions)

• IV.1 Placement accuracy: precise depth control and confined placement via CT packers reduce rework. KPI: top-of-cement within ±3–5 m of plan; verified by tag/volume/thermal signature.
• IV.2 Hydraulics and ECD control: manage friction pressures to avoid losses and ensure hole cleaning. KPI: annular velocity sufficient for solids transport while keeping ECD below fracture gradient.
• IV.3 CT fatigue and reliability: track bend cycles and high-pressure exposure to prevent string failure; maintain BHA reliability to limit trips.
• IV.4 Rig-time reduction: rigless or hybrid campaigns; batch P&A across wells to amortize mobilization. KPI: hours per barrier set; NPT minimization.
• IV.5 Well control integrity: redundant barriers in PCE, real-time pressures, gas detection; minimize exposure during underbalanced phases.
• IV.6 HSE and emissions: smaller footprint than rigs; optimize pump scheduling, engine load, and logistics to reduce fuel burn; use lower-embodied-CO₂ cement where feasible.

V. Typical challenges/bottlenecks and mitigation

• V.1 Losses while cementing: mitigate with lower-density/extended slurries, staged placement, LCM pills, ECD reduction via lower rates or nitrified fluids; use packers to confine placement.
• V.2 Poor bonding/contamination: aggressive pre-flush/spacers, mechanical scraping/jetting, controlled pull-out rates, and WOC compliance; verify compressive strength before tagging.
• V.3 Achieving behind-casing isolation: perforate–wash–cement with adequate perforation density; wash until low solids and stable returns; consider straddle packers for zonal control.
• V.4 Stuck CT/differential sticking: maintain circulation, avoid extended static periods, manage annular velocity, use lubricious pills, monitor downhole pressure via memory gauges.
• V.5 CT reach/drag limits: pre-job force modeling; select CT OD/wall for stiffness; optimize fluids for drag reduction; use vibration tools or tractors only if compatible with P&A scope.
• V.6 Gas influx while underbalanced: keep overbalance where possible; if lifting, maintain dynamic kill margins, use reliable check valves, and monitor returns with choke control.
• V.7 Verification uncertainty: combine tag, pressure tests, and temperature/pressure memory; if ambiguous, perform top-up cement via CT.

VI. Why CT in P&A matters economically and operationally

• VI.1 Cost and schedule: CT enables rigless or hybrid operations, cutting rig days and mobilizations; targeted placement reduces rework and NPT.
• VI.2 Barrier quality and compliance: controlled annular cleaning and confined cementing raise the probability of achieving regulatory barrier criteria on first attempt.
• VI.3 Safety and environmental assurance: fewer heavy lifts and smaller crews than rig campaigns; better well control during live interventions; improves long-term leak-tightness.

Key calculations and formulas used in CT P&A

• VII.1 Hydrostatic pressure

  \( P_h = \rho\, g\, h \)

  Use to confirm overbalance during placement; in field units: \( P_h\,[\text{psi}] \approx 0.052\, \text{MW}\,[\text{ppg}] \times \text{TVD}\,[\text{ft}] \).

• VII.2 Equivalent circulating density (ECD)

  \( \text{ECD}\,[\text{ppg}] = \text{MW}\,[\text{ppg}] + \dfrac{\Delta P_{\text{ann}}\,[\text{psi}]}{0.052 \times \text{TVD}\,[\text{ft}]} \)

  Keep ECD below fracture gradient to minimize losses, especially during annular wash/cement.

• VII.3 Annular velocity and pump rate

  \( \text{AV} = \dfrac{Q}{A_{\text{ann}}} \), where \( A_{\text{ann}} = \dfrac{\pi}{4} \left(D^2 - d^2\right) \)

  Select \(Q\) to achieve solids transport (typical target 0.5–1.0 m/s, estimated) without excessive ECD.

• VII.4 Cement volume (inside casing)

  \( V_c = A_{\text{hole}} \times L_{\text{plug}} \times (1 + E) \)

  Where \(E\) is excess (typically 10–30% estimated), and \(A_{\text{hole}}\) is the net annular area the cement occupies.

• VII.5 Balanced plug displacement

  Displace so hydrostatic above and below plug are equal at setting depth. Pump time: \( t = \dfrac{V_{\text{pump}}}{Q} \).

  Spacer train: preflush ? lead ? tail; density hierarchy to prevent fallback and contamination.

• VII.6 Pressure test acceptance (example)

  Hold a specified pressure (e.g., 500–1,500 psi, duration 10–15 min, estimated) with acceptable leak-off. Actual criteria per operator/regulator.