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Modern technology makes centralizers a surprisingly simple secret to enhancing offshore well integrity.
Many new engineering solutions have been motivated by the challenge of well integrity in the HP/HT conditions common in offshore fields. The drive to improve offshore well integrity is natural and necessary, and the innovation spurred by this goal has benefitted the industry as a whole. However, in addition to seeking out new solutions, the importance of established, proven technologies must not be forgotten. Mechanical centralizers might not be the first thing that comes to mind when one thinks of high-tech downhole tools, but their importance to well integrity should not be underestimated.
Many well integrity issues such as poor zonal isolation arise because of improper or ineffective cementing. Inadequate displacement, channeling and incomplete coverage all can lead to poor zonal isolation. The effectiveness of industry best practices to improve displacement efficiency, such as optimizing rheology, flow rates and pipe movement, is limited without proper centralization. When centralizers are selected and spaced correctly, standoff (Figure 1) between the casing string and the parent casing or open hole is increased. This enables cement to be placed all around the annulus for a cohesive seal.
FIGURE 1. Casing standoff can be calculated from the diameter of the open hole or previous casing (Dw), the diameter of the casing (Dp) and the shortest distance between the casing and the openhole wall (Wn). A standoff ratio of 80% to 90% is recommended for cementing. (Source: Weatherford)
Many variables, such as inclination, spacing, restriction, actual hole size and fluids, will affect centralizer performance. Offshore wells in particular have additional centralization challenges. Heavy casing strings and build, drop and turn sections in deviated wells influence hook load, torque and drag, and running forces while getting to bottom. Often, well architecture requires centralizers to pass through tight restrictions such as wellhead housings. In underreammed holes, centralizers will need to pass through the previous casing inside diameter and then provide standoff in the larger openhole section. The biggest challenge overall for offshore wells is balancing the needs of getting good standoff with getting casing to target depth.
Back to basics The role of a centralizer varies for different casing strings and applications, but in essence it is designed to keep the casing centered in the wellbore during cementing operations. It also helps prevent differential sticking by reducing the surface area of the casing that contacts the wellbore.
Since its emergence in the early 1900s, centralizer technology has changed to reflect the more extreme depths, lengths and conditions of wells through enhanced designs, stronger materials and improved manufacturing techniques. Specially designed centralizers can help run casing to total depth in the most challenging wells by reducing running and starting forces, passing through ultratight restrictions or reducing torque and drag.
Despite the benefits centralizers bring to well cementing, negative misperceptions persist within the industry; for example, it is a belief that centralizers will become stuck downhole, will interfere with running casing to bottom or will take too much time to run. Often, these perceived issues originate from experience using the wrong kind of centralizer for an application. However, they can be remedied by getting back to basics: stepping back during the design and planning process and considering the basic needs for proper casing centralization.
Though centralizer design and materials have improved, the core methodology of selection according to well conditions has remained consistent throughout the years. Using a back-to-basics methodology emphasizes running only what is needed to meet well objectives. Whereas an engineer in the 1950s used rules of thumb, slide rules and pencils to place centralizers, today’s engineers have the best technology and tools available to select and recommend specific centralizer types and placement for expected well conditions. Simulators and placement models aid the selection of the optimal centralizer design and placement for using the fewest centralizers possible to achieve objectives such as standoff, torque reduction, drag reduction or a combination of all three. Optimizing and balancing design considerations for each string results in gains in value and efficiency.
Putting it into practice In the following case study, the service provider applied a back-to-basics methodology to select the optimal centralizer type based on well conditions. An operator planned to run a 17-in. liner in the North Sea. Requirements for this job included the ability to rotate casing during cementing, to pass through a 17.77-in. restriction and to provide adequate standoff for cementing a 20-in. openhole section with a 27-degree deviation.
The 0.77-in. clearance outside the liner and the rotation requirement eliminated many options in terms of centralizer type. For example, the outer diameter (OD) of a standard welded centralizer or any type of centralizer requiring a stop collar would be too large. On the other hand, solid-bodied or rigid centralizers could provide the ability to rotate and pass through the restriction, but they could not provide adequate standoff in the 20-in. openhole section.
The selected sub-mounted bow spring centralizer allowed rotation and recessed to an OD of 17 ½ in., which enabled clearance through the restriction (Figure 2). Once the centralizer sub reached the open hole, the bow springs expanded to meet the 20-in. openhole diameter with a standoff calculated between 76% and 100%. While being run in the hole, the liner string passed through the restriction without any notable change in string hookload weight, reached total depth without issue and was rotated during the cement job.
FIGURE 2. The matrix above shows criteria considered for choosing a centralizer to optimize standoff in the 17-in. liner case study. (Source: Weatherford)
In another case study in the Norwegian Sea, proper centralizer selection enabled a 7-in. liner to reach bottom in a depleted formation without differential sticking. Aside from reaching target depth, the operator sought to improve cement placement by allowing rotation and providing a minimum of 75% standoff through the cemented section in an 8 ½-in. open hole. Centralizer simulation software assisted in evaluating candidate centralizer types, estimating spacing and standoff and finally selecting the optimum program for this well profile to exceed the requirements for standoff and minimizing differential sticking.
The service company selected a 7-in. by 8 ½-in. single-piece slip-on bow-spring centralizer for its ability to provide a larger flow bypass area than rigid centralizers, its exceptional standoff capabilities, the absence of starting and running force requirements in the desired hole size and its ability to pass through tight spots in the open hole without affecting standoff. Per the operator’s request, two types of standoff models were run with this single-piece centralizer program at a spacing of two centralizers per joint. The first model evaluated standoff and side forces with displacement fluid inside the casing and cement in the annulus. This type of model resulted in an optimistic 96% standoff between centralizers and 97% at each centralizer.
The second model evaluated the same centralizer program with cement inside the casing and mud in the annulus; since cement is typically heavier than the mud it is displacing, this model assumes a higher load on the centralizers than the first model. Even with this worstcase scenario, standoff was calculated to be 93% between centralizers and 94% at each centralizer— well above the 75% minimum requirement. When running this configuration of centralizers, the operator reached the bottom on the first attempt, mitigated risk of differential sticking and improved zonal isolation in the cemented section for subsequent perforation and completion operations.
Without proper centralization and spacing, cement cannot flow completely around the outside of the casing, and without a complete cement sheath, gas and fluid migration can severely compromise well integrity. While the basic concept of centralization has remained the same for a century, modern technology can optimize centralizer selection and spacing to improve efficiency. Benefits of this type of optimization include reducing running and drag forces, which makes it easier to reach bottom, and increasing standoff for a better cement job.
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