Nitrogen Kickoff Through Coiled Tubing, Step by Step

Technicians: how it worksWell completion & intervention Production9 min read

Key takeaways

A well "dies" when the hydrostatic pressure of its fluid column exceeds reservoir pressure. Example: 8.6 ppg at 8,000 ft gives 3,577.6 psi against a reservoir pressure of only 3,200 psi.
Nitrogen injected through the CT lightens the column; the well flows once bottomhole pressure drops below reservoir pressure.
The BHA is simple: connector, double flapper check valve, optional bar, and a large-bore nozzle.
In a typical procedure: run in at 50 ft/min (15 m/min), slow to 10 ft/min about 100 ft above the fluid level, inject at a low rate while running, then at the design rate at the planned depth.
Injecting too deep can push nitrogen into the formation; too slow a rate makes lifting inefficient. That is why the job is planned with simulation.

Educational content only: procedures and operating values vary between companies and wells. Always follow your company’s approved procedures, your supervisor’s instructions and the permits in force at your site.

When does a well "die"?

After a workover, after acidizing, or when water gradually accumulates in gas wells, the tubing can fill with fluid heavier than the reservoir fluid. The column's pressure then exceeds reservoir pressure, the reservoir cannot lift the fluid to surface, and the well is said to be dead. This is where coiled tubing comes in: a long continuous steel pipe spooled on a reel, run inside the tubing without making up connections, carrying nitrogen to the required depth.

A worked example: why won't the well flow?

A well with mid-perforation depth 8,000 ft TVD is full of 8.6 ppg brine; reservoir pressure is 3,200 psi.

P = 0.052 × 8.6 × 8,000 = 3,577.6 psi

The column (3,577.6 psi) exceeds reservoir pressure (3,200 psi) by about 378 psi, so the well cannot flow.

Assume, for simplicity, we want 150 psi at the wellhead and a drawdown of 300 psi. The liquid column must then be no taller than:

h = (3,200 − 300 − 150) ÷ (0.052 × 8.6) = 2,750 ÷ 0.4472 ≈ 6,149 ft

That means removing about 1,851 ft of liquid, roughly 10.7 bbl in 2-7/8 in tubing with a capacity of 0.00579 bbl/ft. This simplification only illustrates the idea; it ignores gas weight, friction and inflow from the formation. Real designs are done by simulation.

The principle: how does nitrogen lift the liquid?

Nitrogen is an inert, light gas and relatively safe with hydrocarbons because it neither burns nor supports combustion. Injected through the CT and released at the nozzle at a given depth, it mixes with the liquid above, lowering the mixture density; the bubbles expand as they rise and push liquid ahead of them. This happens in the annulus between the CT and the tubing. When bottomhole pressure falls below reservoir pressure, reservoir fluid or gas starts to enter, and if the reservoir is capable, flow continues on its own after the CT is pulled.

Figure: schematic of an N2 kickoff. The coiled tubing runs inside the production tubing; nitrogen leaves the nozzle and lightens the fluid column; returns flow up the CT × tubing annulus to the choke and on to the tank or separator.

What happens downhole, stage by stage

Picture the well from the inside during the job:

Running through the empty section: the CT is full of nitrogen and nozzle pressure is low because the rate is low. Gas vents up the well without lifting much.
Entering the liquid: bubbles appear in the column above the nozzle. They rise and expand as the surrounding pressure falls, pushing some liquid upward.
At lift depth: at the design rate the column above the nozzle becomes a light mixture. Liquid starts to reach the choke and bottomhole pressure falls gradually.
When the reservoir kicks in: once bottomhole pressure is below reservoir pressure, reservoir fluid or gas enters. You see the returns change in type and temperature, and wellhead pressure rise.
While pulling out: a low injection rate keeps the column light until the CT is out. If the reservoir is capable, the well keeps flowing.

Planning before the job

Typical procedures stress planning with computer simulation wherever possible. Data needed include:

Flowing bottomhole temperature (FBHT) and shut-in bottomhole pressure (SIBHP).
Density of the fluid now in the well and of the produced fluid, and the expected gas-oil ratio (GOR).
The completion diagram, restrictions and their IDs, the well trajectory and deviation.

Simulation outputs include:

Optimum injection depth: too deep and nitrogen may be pushed into the formation without the well flowing; too shallow and at a lower rate, large volumes of nitrogen lift little liquid.
Optimum injection rate: SPE 143337, for example, shows there is an optimum nitrogen rate. Too high a rate raises annular friction; too low allows gas to slip through the liquid (slippage).
CT size: too large narrows the annulus, raising friction and possibly losing returns; too small gives low rates and a wide annulus with more slippage.
Total nitrogen volume, including what is lost cooling down the equipment.

If slippage is unacceptable, a foamer can be added, bearing in mind that foam can cause problems handling returns at surface.

The bottomhole assembly (BHA)

The principle here is to minimise pressure loss through the assembly. Usual components:

Connector on the end of the CT.
Double flapper check valve: two non-return valves that stop well pressure and fluids flowing back into the CT, a key barrier because the CT works in a live well.
Straight bar, about 6 ft long, if needed.
Nozzle: a single port with the largest possible ID.

Surface rig-up

From the top: the injector head that runs and pulls the CT; the stripper that seals around the moving CT; the CT BOP with its rams; a riser or lubricator; then the christmas tree. Connected to the stack:

Nitrogen unit: converts liquid nitrogen to high-pressure gas and pumps it.
Return line: from the production side of the tree to the choke, then to the tank, separator or flare according to site design.
Lines: all surface lines are secured and restrained before starting.

Pressure tests

All surface equipment (CT, BOPs, lines) is hydro-tested before any gas is introduced.
The CT is displaced to nitrogen, and a gas test is carried out if the client or the procedure requires it.

Execution steps

Prepare the CT and pressure-test it as per approved procedures.
Displace the CT to nitrogen and perform a gas test if required.
Open the well and run in hole (RIH) at 50 ft/min (15 m/min).
If there is a static fluid level, slow to 10 ft/min (3 m/min) about 100 ft (30 m) above the expected level, then return to 50 ft/min once in the liquid.
Inject nitrogen at a low rate while running in to lighten the column before reaching lift depth. If a foamer is used, its pump must run to keep the correct ratio.
At the planned depth, inject at the design rate. Monitor CT pressure, wellhead pressure, flow rate and returns.
When the well is flowing satisfactorily, pull out (POOH) at 50 ft/min while continuing to inject nitrogen at a low rate, e.g. 300 scf/min.
At surface, do not rig down before monitoring the well and confirming that flow is stable.
After rig-down, inspect the BHA for wear, especially the check valves.

The figures above (50 and 10 ft/min, 300 scf/min) come from a published typical procedure. Your figures are set by the job programme, the simulation and the service company's procedures.

Signs of success and failure during the job

Success: gradual rise in wellhead pressure and return rate; returns change from heavy liquid to a gas-liquid mix and then to reservoir fluid; flow continues after injection is reduced.
Injecting into the formation: CT pressure rises without returns matching the gas volume. Stop and review depth and rate.
Gas slippage: lots of gas with little liquid. Rate or depth is wrong, or a foamer is needed.

Hazards and safety

Gas under pressure: stored energy in compressed gas is far greater than in liquid at the same pressure, so a connection failure is violent. Do not stand next to pressurised lines.
Liquid nitrogen: extremely cold and causes cold burns. Proper PPE is mandatory.
Asphyxiation: nitrogen displaces oxygen and can collect in low or enclosed spaces such as the wellhead cellar. Use an oxygen monitor.
CT in a live well: barriers (check valves, stripper, BOP) must be intact and tested, and the CT's internal and external pressure limits respected as per the programme.
Returns: may carry hydrocarbon gas or H2S and must be routed safely to processing or flare.

Checklist before opening the well

Before running in, the supervisor and crew review a short list together. It does not replace company procedure but summarises the key points:

Job programme: injection depth, design rate, nitrogen available plus contingency, maximum pressure limits for the CT and wellhead.
Completion diagram: nipple and restriction depths, the smallest ID, and confirmation that the BHA passes it safely.
Barriers: test results for the BOP, stripper and lines, and check-valve function.
Return path: correct valves open to the choke and the tank or separator; no closed valve on the way that could suddenly raise pressure.
Communication: who gives pump start and stop orders, and how the CT operator talks to the nitrogen unit and the choke operator.
Emergency: location of gas and oxygen detectors, muster points, and the quick shut-in plan.

Common mistakes on site

Running fast into the liquid: entering heavy fluid at speed can cause pressure surges and misleading weight readings. Slow down before the fluid level.
Stopping injection abruptly: liquid falls back over the nozzle, and it may take time and extra nitrogen to restore lift.
Ignoring returns: without monitoring the volume coming out, you cannot tell whether lift is working or gas is going into the formation.
Rigging down too early: some wells flow briefly then die again. The typical procedure requires confirming stable flow before rig-down.
Ignoring CT condition: fatigue accumulates with every spool and unspool cycle and is tracked for each reel by service companies. See the lesson Coiled tubing fatigue.

Summary for the technician

An N2 kickoff is a direct application of hydrostatics: lighten the column until bottomhole pressure is below reservoir pressure. Success depends on three things: good planning (depth, rate, CT size), sound barriers and continuous monitoring. To go further, see the coiled tubing lesson series and the lesson on gas lift.

Test your understanding

Test your understanding

Why does a well stop flowing after a workover that filled it with brine?

Explanation: Hydrostatic pressure = 0.052 × density × depth. If it exceeds reservoir pressure, the reservoir cannot push fluids to surface.

What is the pressure of an 8.6 ppg brine column at 8,000 ft TVD?

Explanation: 8.6 × 0.052 × 8,000 = 3,577.6 psi.

What does the double flapper check valve in the BHA do?

Explanation: It is a barrier against back-flow into the CT, which matters because the CT works inside a live well.

What often happens if the CT is too large for the tubing?

Explanation: A narrow annulus acts like a choke, raising friction pressure and working against the goal of lowering bottomhole pressure.

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