Proper centralizers can improve horizontal well cementing

Holger Kinzel
Weatherford Oil Tool GmbH
Langenhagen, Germany

• Typical bow-type centralizer (Fig. 2). [10,146 bytes]
• Semirigid centralizer with flat, stiff bows designed for horizontal sections (Fig. 3). [11,273 bytes]
• Field technician installing aluminum, spiral rigid centralizers (Fig 4). [42,020 bytes]
• The bows on the downhole activated centralizers are locked down before running in the well (Fig. 5). [50,359 bytes]

The selection and spacing of appropriate centralizers can improve the cementation of high-angle and horizontal wells.

Mud removal is one of the most important factors in obtaining a good cement job. Effective centralization assists in mud removal and helps ensure an even cement coat around the casing. Certain running procedures, such as pipe reciprocation and rotation, enhance the mud displacement process.

Centralizers for horizontal wells have to fulfill two requirements: They should have a high restoring capability and a low moving force, and they should allow pipe rotation and reciprocation.

Conventional bow-type centralizers have been used successfully in some horizontal wells. But as the horizontal section length increases, special centralizers, such as low-moving-force, bow-type centralizers and rigid centralizers, may be necessary.

For economics and for simplicity of design, a majority of horizontal wells worldwide have been completed open hole or with a slotted liner. Many of these wells may face a production or mechanical problem that may be difficult to solve if a liner or casing string is not cemented in the horizontal section.

Cementing liners

Wells are cemented to achieve two main goals: to form a tight seal around the pipe and to reinforce the pipe mechanically. Therefore, completions with cemented liners, instead of open hole or uncemented liner completions, are typically preferable in both vertical and horizontal wells.

In horizontal wells, however, open hole completions or uncemented liners are often used because they are initially less expensive options than cemented liners. The open hole completions are typically selected for fractured limestone, and uncemented slotted liners are often selected for well-consolidated sandstone reservoirs.

The production history of some of these wells shows that these completions may not always be the most economical solution in the long term for a particular well or field. Remedial measures to maintain a high production rate, such as selective acidizing, sealing off water or breakthrough, and hydraulic fracturing, are not possible if the liner is left uncemented.

Pulling a slotted liner and replacing it with a cemented liner is difficult, if not impossible, once remedial work is necessary. This problem has been recognized by a number of operators, some of which have been cementing liners in horizontal and high-angle wells for several years. ^1-3

The following general recommendations on how to obtain good cementation in horizontal or high-inclination wells are based on field experiences. Wells should be analyzed individually because no single option works perfectly in every well. Thus, intensive engineering should be part of every high-inclination well project, and the planning should include careful cementing and centralizer engineering.

• Mud removal
In all vertical, inclined, and horizontal wells, a main goal to achieve a good cementation is effective displacement of the mud by the cement. The factors affecting mud removal efficiency include pipe centralization, pump rate, cement/mud density ratio, and fluid rheology.

Mud pockets and pipe eccentricity in the borehole can cause problems during cementing (Fig. 1 [117,968 bytes]). A high degree of mud removal is desired to avoid channeling problems caused by mud pockets and to prevent a high mechanical load on the pipe because portions of the annulus are filled with mud. Additionally, cement contaminated with mud will not achieve its final strength.

• Flow properties
The cement slurry and the mud have completely different tasks and, therefore, the flow properties of each type of fluid are different. Both are typically non-Newtonian fluids with different viscosities, shear strengths, and weights.

The use of appropriate fluid spacers is one method to bridge the two different fluids.

• String movement
Several theoretical studies and numerous practical applications have shown that movement of the casing string while the cement is pumped enhances mud removal. ^{1 4-5} Both string rotation and string reciprocation have been proven effective, and in certain cases a combination of the two gives even better results. In typical operations, the casing is reciprocated about 20-30 ft, and the casing is rotated at about 20-30 rpm.

Of the two, rotation might be more desirable than reciprocation. If a liner is on bottom, it might be safer not to reciprocate the pipe. If the pipe is pulled up, the pipe may stick and the liner may not be able to be pushed back to bottom. If the pipe sticks during rotation, the rotation can stop with little danger of not being able to set the liner in the proper place.

• Cement properties
The cement slurry design is critical, but a detailed description of all parameters involved is beyond the scope of this article. The following general guidelines should be taken into consideration:

- The free water content in the cement slurry should be minimized to prevent channeling.
- Cement sedimentation should be minimized.
- Cement shrinkage (typically 1-2%) should be minimized. Certain cement additives can minimize shrinkage or even increase the cement volume.

• Hole cleaning
Hole cleaning should be considered during the planning and engineering of a horizontal well. Beds of cuttings will support mud pockets and should be avoided. During drilling, frequent check-trips, a sufficient pump rate, and a well-prepared mud should ensure adequate cuttings removal in the horizontal section. Additionally, it is recommended to pump at least two complete hole volumes before the casing or liner is run.

Centralization

Proper string centralization is essential for effective mud removal. Eccentric strings can lead to unequal annuli on the high and low side of the hole. Because the spacer and then the cement tend to follow the path of least resistance, large mud sections can be left on the low side of the hole.

What is considered a good centralization? The old standard of 67% standoff, as formerly recommended by the American Petroleum Institute (API), was considered adequate for most wells.

However, the current API specification 10 D states that "67% may or may not be sufficient for a good cementation . ⁶ The centralizer keeps the pipe in a concentric position relative to the hole axis. If the pipe is exactly centered, the standoff is 100%. If the pipe touches the borehole wall, the standoff is 0%.

The best mud displacement occurs as standoff approaches 100%. However, this value cannot always be obtained. Practical experience and laboratory tests have shown that standoff values of 80-90% are considered adequate, even for horizontal wells. With properly selected centralizers, these values can be achieved.

Selecting the proper centralizer for a particular well requires a knowledge of the parameters by which a centralizer is defined. API 10 D defines the forces which characterize the traditional bow-type centralizer (Fig. 2). The starting force is the force needed to push a centralizer into the casing string in the well. The running force, or moving force, defines the drag from the friction of the centralizer bows against the borehole wall. The restoring force defines the centralizing capability of a bow-type centralizer. The higher the restoring force, the better the centralization.

Torque and drag

Centralizer engineering combines mathematical simulation models with practical experience. The engineer must find a balance between a high restoring force and a low running force.

In highly inclined or horizontal wells, the pipe has to be pushed downhole. Thus, high drag forces from additional friction cannot be tolerated. The additional friction from certain centralizer designs could become a problem if the inclined section is very long.

Additionally, string rotation is desired to enhance mud removal during cementation. Certain centralizers are designed to allow the string to be reciprocated and rotated.

The use of centralizers minimizes the risk of differential sticking, especially in areas of high formation permeability. The area of the centralizer bows touching the formation is much smaller than the area of an uncentralized string (or slotted liner) lying on the low side of the well. Drag forces from differential pressure are therefore lower if centralizers are used.

Centralizer placement

Various mathematical models have been used throughout the drilling industry to optimize the centralizer placement; it is important to realize that these mathematical equations and relationships typically describe model situations only. ^6-7 'The actual standoff in a borehole depends on many factors which vary from region to region.

There is no method of actually looking into the well with a "standoff logging tool." Some methods of logging, such as cement bond logs, can give a secondary indication about the standoff by determining the success of the cementation.

It is beyond the scope of this article to compare the different methods of standoff calculation. Each method, however, follows a similar process. The following are the basic steps to determine the optimum centralizer placement:

• Select a centralizer with a low moving force.
• Select a practical centralizer spacing.
• Calculate the lateral load at each centralizer location.
• Calculate the centralizer deflection.
• Determine the sag between the centralizers.
• Calculate the total drag forces.
• Change the centralizer spacing if the drag is too high or if the standoff is not adequate.
• Return to the second step until an optimum is reached between a good standoff and a low drag force.

Practical centralizer spacing means that engineering judgment must be used to interpret calculations. For example, if a numerical simulation or calculation determines a centralizer spacing of 22.52 ft, it would be advisable to install two centralizers per 40-ft casing joint instead of using a tape to measure every 22.52 ft along the casing. Although the centralizer positions may be calculated with mathematical models, the results should be regarded in a practical manner.

The lateral load is the combined force of the string buoyed weight component and the tension at that particular point. Because mud removal is most critical when the cement reaches the shoe and the displacement process begins, the buoyancy factor should be calculated conservatively using the mud weight outside the pipe and the cement weight inside.

The centralizer deflection is calculated by using the results of the API restoring force test. 6 The lateral load is the input variable used to evaluate how much a bow-type centralizer will be compressed by the particular force applied. The sag between the centralizers can be calculated a number of ways; many of the calculation methods are based on a type of "chain-line" equation that takes into account the buoyed weight of the pipe.

The total drag force can be shown graphically in a hook load prediction diagram. A high drag force in the horizontal section can be problematic if the weight of the string above this section is not large enough to push the casing or liner in place. Therefore, centralizers with a low moving force are preferred.

Bow-type centralizer

The principle of a conventional bow-type centralizer is based on the design of the spring. The bow-type centralizer is characterized by a high restoring capability, depending on the lateral load on the centralizer. However, a high restoring force results in a high moving force.

The elasticity of the centralizer gives it a limited capability to be run through tight spots. Specially designed centralizers have been developed for the specific requirements of long horizontal sections or high-inclination extended reach wells.

Several horizontal wells have been equipped with conventional nonwelded, bow-type centralizers; however, in some applications additional drag because of the moving force of the bows cannot be accepted. A semirigid centralizer with a very flat but stiff bow was designed for long horizontal sections or extended reach wells (Fig. 3). This type of centralizer has a nonhinged collar and bows firmly fixed to the collar by a special welding process to allow free pipe rotation. Several horizontal wells have been cemented successfully using this type of centralizer. ⁸

Rigid centralizer

The spiral rigid centralizer provides a large standoff without a large moving or starting force (Fig. 4). This type of centralizer has been successfully used in numerous high-inclination and horizontal wells. 1 This type of rigid centralizer gives the casing string a fixed standoff.

The outside diameter is in the range of the diameter of an undergauge drilling stabilizer, thus ensuring that the centralizer can pass through the borehole just as the bottom hole assembly did during drilling. A casing string equipped with two centralizers per joint, which is quite common in horizontal wells, is regarded as a stiff assembly. The well must therefore be carefully reamed before this configuration is run. The use of rigid centralizers is recommended in gauge holes with no tight spots and no large washouts.

The centralizer can be mounted on the pipe between stop collars to allow a maximum of movement during running in. Rotation of the pipe is supported by the centralizer because the surface between the aluminum centralizer and the steel pipe acts like a friction bearing.

The spiral shape of the blades produces a vortex motion of fluids by restricting the flow area and by directing the fluid off the borehole axis. This type of flow enhances borehole cleaning and mud removal while the spacer or cement is pumped.

Downhole activated centralizer

The spiral rigid centralizer is best used in a gauge borehole, but if the hole is oval shaped or has large washouts, the rigid centralizer loses some of its advantages. In such cases, a bow-type centralizer with a high restoring force is more desirable, but a centralizer with a high restoring force usually also has a high moving force.

A downhole activated centralizer was developed to be run in wells with drag or clearance limitations. This type of centralizer is especially useful for high-inclination extended reach or horizontal wells that may have drag limitations. The use of these centralizers can reduce the total drag force by approximately 30%. Thus, a well with a longer extended reach can be drilled.

The downhole activated centralizer is based on the conventional nonwelded, bow-type centralizer but can be applied to other types of spring bow centralizers as well. The centralizer bows are compressed and held together by a steel band attached to the bows (Fig. 5). The steel band is held locked until certain preset conditions are met. The lock is activated either by hydrostatic pressure, by downhole temperature, or by a chemical fluid pumped through the annulus.

A pressure-release module can be adjusted to the hydrostatic pressure at a given depth. Each centralizer is automatically released to its full restoring capability as it passes this depth. The pressure-release lock can also be used in horizontal wells, provided the difference between the formation pressure and the formation strength leaves a pressure window large enough to safely activate the lock. In these cases, the blowout preventer is closed, and the well bore pressure is slightly increased above the formation pressure until the lock-releasing pressure is reached.

A temperature-release lock is also applicable for use in horizontal wells. The lock is set to activate in the temperature window between the static bottom hole temperature and the circulating temperature. While the casing is run in the hole, the hole is circulated periodically to cool the well and ensure that the releasing temperature is not reached prematurely. After the string is in place, circulation is stopped to allow the bottom hole temperature to reach the releasing temperature of the lock.

The third method for active control of the release mechanism is the use of chemicals pumped down the annulus. After the casing is in place, the pH value of the spacer fluid or the mud system is lowered slightly with a low concentration of an organic acid. As the low pH fluid passes the centralizers, the locking devices are activated to open the bows. ⁹

The downhole activated centralizers have been used successfully in deviated wells offshore Italy. ¹⁰

References

1. Possamai, E., and Bianchi, R. "Casing Operations on Deep, Directional, and Horizontal Wells: A New Approach on Planning and Follow-up," IADC/SPE paper 23924, presented at the 1992 IADC/SPE Drilling Conference, New Orleans, Feb. 18-21, 1992.
2. Matson, R., et al., "Cementing horizontal holes becoming more common," OGJ, Dec. 17, 1990, pp. 40-46.
3. Moritis, G., "Worldwide horizontal drilling surges," OGJ, Feb. 27, 1989, pp. 53-63.
4. Calvert, D.G., et al., "API Oilwell Cementing Practices," Journal of Petroleum Technology, November 1990.
5. Smith, T.R., "Cementing Displacement Practices-Field Applications," Journal of Petroleum Technology, May 1990.
6. "Specification for Bow-Spring Casing Centralizers," API Specification 10D, fourth edition, Jan. 1, 1991.
7. Juvkam-Wold, H.C., and Wu, J., "Casing Deflection and Centralizer Spacing Calculations," SPE Drilling Engineering, December 1992.
8. Niggemann, L., and Ehlers, R., "Horizontal Drilling in a Depleted Sour Gas Reservoir, A New Application," Oil Gas-European Magazine, 3rd quarter 1991.
9. Kinzel, H., and Heidecke, K., "A New Contribution to Cementing Technology: The Development and Field Application of a Downhole Activated Centralizer," OTC paper 7070, presented at the 24th Annual Offshore Technology Conference, Houston, May 4-7, 1992.
10. Kinzel, H., and Calderoni, A., "Engineering and Operational Aspects of the Use of Downhole Activated Centralizers," SPE paper 26752, to be presented at Offshore Europe '93, Aberdeen, Sept. 7-10, 1993.

The Author