Volumetric Method, Lubricate and Bleed, and Bullheading

Control and kill are different goals

When normal circulation is unavailable, the supervisor may select volumetric control to manage migrating gas, followed by Lubricate and Bleed to replace gas at the upper well with liquid. These methods require reliable pressure and measured-volume observations. They do not simply release all pressure, and they do not provide permission to improvise an injection treatment. A controlled well is contained and managed; a killed well has the required primary pressure support and verified no-flow condition.

Volumetric control is useful when a reliable bottom reference or circulation path is unavailable, for example with pipe out of the hole or a plugged string. It permits controlled gas expansion while preserving the required bottomhole support. The supervisor specifies the initial pressure reference, safety margin, working-pressure increment, annular capacity, limits and stopping conditions. Those values are selected for the actual geometry and pressure window, not from a universal 100 psi rule.

Convert the working increment to volume

For a uniform vertical interval, the volume corresponding to a working-pressure increment is:

$$V=\frac{P_w C_a}{0.052 MW}$$

With a chosen 100 psi working increment, 12.0 ppg mud and 0.050 bbl/ft annular capacity, the corresponding mud height is 100/0.624 = 160.256 ft and volume is 8.013 bbl. A different capacity produces a different volume. A horizontal or changing-capacity interval needs the appropriate procedure rather than converting all measured length directly into vertical head.

Hold casing pressure during the measured bleed

In the basic cycle, allow migration to build the approved pressure increment, then bleed the calculated mud volume while holding casing pressure approximately constant at that cycle's designated value by controlled choke manipulation. Losing mud head is then offset by the maintained higher surface pressure. Close the choke after the measured volume is collected and allow the next approved increment to develop. The casing-pressure targets rise through successive cycles as the supporting liquid head is reduced.

It is incorrect to bleed the volume while allowing casing pressure to fall back to the previous reference: both surface pressure and mud head would be lost. Track pressure, time, cumulative liquid volume and gas location. Maintain the selected safety margin and remain within the weak-point and equipment limits. Stop or transition as directed when gas reaches the outlet or the capacity/fluid assumptions change. An unmeasured flow is not a volumetric cycle.

Lubricate and Bleed replaces gas with liquid

When gas is accessible at the upper well and normal circulation cannot remove it, a calculated small liquid volume may be injected through the approved route, allowed to settle through the gas and followed by controlled gas removal. The added liquid head permits reducing the surface-pressure support by a corresponding amount while retaining bottomhole support. Settling time depends on geometry and fluid behaviour; a universal 15- or 30-minute wait is not guaranteed.

For example, 2.0 bbl of 15.0 ppg liquid in an effective vertical capacity of 0.100 bbl/ft adds 20 ft of liquid and 15.6 psi of head. If pre-injection casing pressure is 1,000 psi, the ideal post-cycle target is 984.4 psi, subject to the approved margins. If injection temporarily raises pressure to 1,040 psi by compressing gas, removal must address that compression increase as well as the 15.6 psi hydrostatic credit. Bleeding only 15.6 psi from 1,040 would not reach the intended target.

Watch the phase and route

The operator must know whether the collected material is mud or gas, use suitable gas handling and record the pressure reference before each cycle. Do not allow gas from a high-pressure upper pocket into an unqualified pit or work area. The injection and bleed routes require verified valve status, ratings and pressure communication. A failed internal barrier, blocked line or gas trapped beneath a BOP changes the plan. Completion requires the instructed pressure and no-flow verification rather than a predetermined number of cycles.

Bullheading is a separate engineered method

Bullheading pumps fluid into the formation rather than circulating it to surface. It may use available formation injectivity without fracturing; fracture creation is not part of its definition. Selection considers fluid hazards, injectivity, formation and casing integrity, equipment, migration and alternatives. The driller does not select a high rate or force the formation to accept fluid without a supervised engineered plan.

A formation-pressure or fracture estimate minus fluid head is only a simplified surface-pressure estimate, excluding friction. It is not the casing burst limit or an authorised operating limit. For a training formation pressure of 6,656 psi at 8,000 ft with 10 ppg fluid, the zero-friction surface equivalent is 6,656 − 4,160 = 2,496 psi. The actual pressure cap also considers approved casing, connection, BOP and formation limits. If pressure or injectivity departs from the plan, stop or act at its specified limit; equipment failure is not an acceptable inevitable next step.

Non-circulating method balances