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Remedial cementing

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Remedial cementing is undertaken to correct issues with the primary cement job of a well. Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs have the potential to force poor decisions and high risk. Good planning and risk assessment is the key to successful remedial cementing.

Squeeze cementing

Squeeze cementing is a “correction” process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine

  1. If a problem exists
  2. The magnitude of the problem
  3. If squeeze cementing will correct it
  4. The risk factors present
  5. If economics will support it.

Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics.

Squeeze cementing is a dehydration process. A cement slurry is prepared and pumped down a wellbore to the problem area or squeeze target. The area is isolated, and pressure is applied from the surface to effectively force the slurry into all voids. The slurry is designed specifically to fill the type of void in the wellbore, whether it is a small crack or micro-annuli, casing split or large vug, formation rock or another kind of cavity. Thus, the slurry design and rate of dehydration or fluid loss designed into the slurry is critical, and a poor design may not provide a complete fill and seal of the voids.

Squeeze techniques

The following techniques are the six commonly recognized squeeze applications.

Running squeeze

A running squeeze is any squeeze operation in which continuous pumping is used to force the cement into the squeeze interval. This technique is sometimes referred to as a “walking squeeze” when low pump rates and minimal graduating pressure is used. Although the running squeeze is easier to design and apply, it is probably the most difficult to control because the rate of pressure increase and final squeeze pressure are difficult to determine.

As running-squeeze pressure builds, the pump rate should be reduced, creating a walking squeeze. Running squeezes may be applied whenever the wellbore can be circulated at a reasonable pump rate (approximately 2 bbl/min). When applied correctly, most running squeezes are low-pressure applications; however, they often turn into high-pressure applications because of:

  • Unknown formation characteristics
  • The quality of slurry used
  • Lack of job control

Hesitation squeeze

This technique is often used when a squeeze pressure cannot be obtained using a running technique because of

  • The size of the void
  • Lack of filtrate control
  • When the squeeze must be performed below a critical wellbore pressure

During a hesitation squeeze, the pumping sequence is started and stopped repeatedly, while the pressure is closely monitored on the surface. Cement is deposited in waves into the squeeze interval, and the slurry is designed to increase resistance (gel-strength development and fluid-leakoff rate) until the final squeeze pressure is reached. Operators must thoroughly design and test the cement slurry to understand how its properties will change with frequent shutdowns and to safely approximate the shutdown period between pumping cycles. The slurry volume should be clear of all downhole tools before the hesitation cycles begin. For many otherwise large and expensive conventional squeeze applications, a hesitation squeeze can be a safer, less expensive, and effective technique.

High-pressure squeeze

A high-pressure squeeze is an application performed above formation fracturing pressures when fracturing is necessary to displace the cement and seal off formations or establish injection points between channels and perforations. Slurry volumes and leakoff vary with the size of the interval.

“Block” squeezing is the process of squeezing off permeable sections above and below a production zone, which requires isolation of the zone with a packer and retainer, using high pressure to force cement slurry (fracture) into the zone. Cement slurry will not invade a formation unless it is fractured away, creating a large crack to accommodate the entire slurry. Otherwise, dehydration occurs and only the filtrate enters the zone. High pressure is usually required to force all wellbore fluids into the formations ahead of the cement slurry. This technique is often referred to as “bullheading.”

Low-pressure squeeze

A low-pressure squeeze, the most common technique, is any squeeze application conducted below the fracturing pressure. This method can be applied whenever clean wellbore fluids can be injected into a formation, such as permeable sand, lost-circulation interval, fractured limestone, vugs, or voids. Filtrate from the cement slurry is easily displaced at low pressures, and the dehydrated cement is deposited in the void. Whole cement slurries will not invade most formations unless a fracture is readily open or is created during the squeeze process.

Packer/retainer squeeze

Squeeze tools are often used to isolate the squeeze interval and place the cement as close to the squeeze target as possible before applying pressure. Retainers or bridge plugs are used to create a false bottom and are set just below the squeeze target inside the casing or tubing. This procedure seals off the open wellbore below the target (which may be several thousands of feet) and reduces the volume of cement needed for the squeeze. A packer can be run into the wellbore and set above the squeeze interval, between two intervals, or below an interval. Packers allow circulation of the wellbore until the cement slurry is pumped; then the packer is set, which seals off the annulus so the cement can be squeezed through tubing below the packer or down the backside between the tubing/casing annulus above the packer. The following can be more accurately determined and controlled using squeeze tools:

  • Cement volumes
  • Squeeze pressures
  • Squeeze targets

Bradenhead squeeze

This technique is often applied when the problem occurs during drilling (lost circulation) or soon after a primary cement job (weak casing shoe). A Bradenhead squeeze is performed when squeeze tools are unavailable or cannot be run in the hole, or when the operator feels he can successfully control the problem without pulling the drillstring, tubulars, etc. out of the wellbore.

Whether during drilling or completion, a Bradenhead is performed by circulating cement slurry down to the squeeze interval, then pulling the workstring above the top of the cement column. The backside of the wellbore is closed in, and pressure is applied through the workstring to force cement into the squeeze interval. A hesitation squeeze is sometimes used to more effectively pack off the cement into all voids. Most coiled-tubing (CT) squeeze applications are performed using this technique.

Plug cementing

In oil-gas-well construction, a plug must prevent fluid flow in a wellbore, either between formations or between a formation and the surface. As such, a competent plug must provide a hydraulic and mechanical seal.

Factors to consider for a plug job

Each plugging operation presents a common problem in that a relatively small volume of plugging material, usually a cement slurry, is placed in a large volume of wellbore fluid. Wellbore fluids can contaminate the cement, and even after a reasonable wait on cement (WOC) time, the result is a weak, diluted, nonuniform or unset plug. In addition, plugging situations frequently present unique issues that require sound engineering design and judgment. For these reasons, both mechanical and chemical technologies are necessary for successful plugging.

In addition to the issues that are normally considered for a primary cement job, other factors must be carefully considered for a plug job, such as:

  • Displacement efficiency
  • Slurry stability
  • Fluid compatibilities

Application of plugging

Plugging operations are difficult because the work string from a heavier balanced cement plug must be removed from its position above a lighter wellbore fluid. Some of the varied reasons for performing plugging operations are discussed next.

Abandonment

To seal off selected intervals of a dry hole or a depleted well, operators can place a cement plug at the required depth to help prevent zonal communication and migration of any fluids that might infiltrate underground freshwater sources.

Directional drilling/sidetracking

When sidetracking a hole around a non-retrievable fish, such as a stuck bottomhole assembly (BHA) or changing the direction of drilling for geological reasons, it is often necessary to place a cement plug at the required depth to change the wellbore direction or to help support a mechanical whipstock, so the bit can be guided in the desired direction.

Lost-circulation control

When mud circulation is lost during drilling, lost returns can sometimes be restored by spotting a cement plug across the thief (lost-circulation) zone and then drilling back through the plug. Efforts should be made to identify the source and reason for lost returns when planning a plugging job. Factors that can contribute to lost circulation include:

  • Drilling-induced fractures
  • Chemically induced formation instability
  • Natural fractures
  • Vugs
  • High permeability

Well control

Plugs, typically made of cement, are sometimes placed in a wellbore when the well has reached a critical state in which no margins remain between pore and frac pressures and no other options exist. In fact, the drillstring is sometimes intentionally cemented in place because it cannot be pulled without risk of inducing an uncontrolled flow to the surface or a crossflow from a high-pressured zone into a weak or low-pressured zone.

Zonal isolation/conformance

One of the more common reasons for plugging is to isolate a specific zone. The purpose may be:

  • To shut off water
  • To recomplete a zone at a shallower depth
  • To protect a low-pressure zone in an openhole before squeezing

In a well with two or more producing intervals, abandoning a depleted or unprofitable producing zone may be beneficial. A permanent cement plug is used to isolate the zone, helping to prevent possible production losses into another interval or fluid migration from another interval. The integrity of such plugs is frequently enhanced mechanically by placing them above bridge plugs or through and above squeeze retainers. Other methods involve combining the spotting of plugging fluids with the remedial squeeze process of injecting a polymer plugging material into the formation matrix, followed by a small volume of cement slurry to shut off perforations.

Formation testing

Plugs are occasionally placed in the open hole below a zone to be tested that is a considerable distance off-bottom, where other means of isolating the interval are not possible or practical. Although cement is the most commonly used plug material, the following may also serve as plugging agents:

  • Barite
  • Sand
  • Polymers

Wellbore stability

At times during drilling, placing a plugging material across an unstable formation can be beneficial. Polymer, resins, cements, or combinations of these materials can be used to consolidate formations and alter the near-wellbore stresses and formation integrity. A balanced cement plug is sometimes placed to simply “backfill” a severely washed out or elliptical hole section. In such cases, the plug is subsequently drilled out, leaving a cement sheath in place to reduce or prevent further wellbore enlargement and to help return the wellbore to its original diameter and circular shape for improved annular velocities.

References

Noteworthy papers in OnePetro

External links

See also