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Primary cementing placement design
- Cementing through pipe and casing (normal displacement technique)
- Stage cementing (for wells with critical fracture gradients)
- Inner-string cementing through tubing (for large-diameter pipe)
- Outside or annulus cementing through tubing (for surface pipe or large casing)
- Reverse-circulation cementing (for critical formations)
- Delayed-set cementing (for critical formations and to improve placement)
- Multiple-string cementing (for small-diameter tubing)
- 1 Cementing through pipe and casing
- 2 Stage cementing
- 3 Inner-string cementing
- 4 Outside or annulus cementing
- 5 Reverse-circulation cementing
- 6 Delayed-set cementing
- 7 Delayed-set cementing application
- 8 Delayed-set cementing disadvantage
- 9 Multiple-string cementing
- 10 Cementing of high-pressure/high-temperature wells
- 11 References
- 12 See also
- 13 Noteworthy papers in OnePetro
- 14 External links
Cementing through pipe and casing
Conductor, surface, protection, and production strings are usually cemented by the single-stage method, which is performed by pumping cement slurry through the casing shoe and using top and bottom plugs. There are various types of heads for continuous cementing, as well as special adaptors for rotating or reciprocating casing.
Stage cementing is used to ensure annular fill and seal across selected intervals whenever none of the following cementing applications can be performed:
- Continuous single-stage
- Lead and tail
- Lightweight (foamed, ceramic spheres, etc.)
Stage cementing tools
Stage-cementing tools, or differential valve (DV) tools, are used to cement multiple sections behind the same casing string, or to cement a critical long section in multistages. Stage cementing may reduce mud contamination and lessens the possibility of high filtrate loss or formation breakdown caused by high hydrostatic pressures, which is often a cause for lost circulation.
Stage tools are installed at a specific point in the casing string as casing is being run into the hole. The first (or bottom) cement stage is pumped through the tool to the end of the casing and up the annulus to the calculated-fill volume (height). When this stage is completed, a shutoff or bypass plug can be dropped or pumped in the casing to seal the stage tool. A free-falling plug or pumpdown dart is then used to hydraulically set the stage tool and open the side ports, allowing the second cement stage (top stage) to be displaced above the tool. A closing plug is used to close the sliding sleeve over the side ports at the end of the second stage and serves as a check valve to keep the cement from U-tubing above and back through the tool.
Displacement stage cementing
The displacement stage-cementing method is used when the cement is to be placed in the entire annulus from the bottom of the casing up to or above the stage tool. The displacement method is often used in deep or deviated holes in which too much time is needed for a free-falling plug to reach the tool.
Fluid volumes (mud, spacer, cement) must be accurately calculated and prepared on locations and densities closely measured to prevent over- or underdisplacement of the first stage.
- Overdisplacement can result in improper opening of the tool to apply the second (upper) stage, resulting in excess pressures or job failure.
- Underdisplacement creates a gap (void) in the cement column at the stage tool, which results in poor zonal isolation.
Two-stage cementing is the most widely used multiple-stage cementing technique. However, when a cement slurry must be distributed over a long column and hole conditions will not allow circulation in one or two stages, a three-stage method can be used. The same steps are involved as in the two-stage methods, except that there is an additional stage. Obviously, the more stages used in the application, the more complicated the job will become. Although stage cementing was very popular many years ago, new foamed-cement and nonfoamed-ultralightweight-cement technologies have successfully reduced the need for multistage cementing in many operations.
When large-diameter pipe is cemented, tubing or drillpipe is commonly used as an inner string to place the cement. This procedure reduces the cementing time and the volume of cement required to bump the plug. The technique uses modified float shoes, guide shoes, or baffle equipment, with sealing adaptors attached to small-diameter pipe. Cementing through the inner string permits the use of small-diameter cementing plugs. If the casing is equipped with a backpressure valve or latchdown baffle, the inner string can be disengaged and withdrawn from the casing as soon as the plug is seated, while preparations are made to drill deeper.
Outside or annulus cementing
A method commonly used on conductor or surface casing to bring the top of the cement to the surface consists of pumping cement through tubing or small-diameter pipe run between casings or between the casing and the hole. This method is sometimes used for remedial work. Casing can suffer damage when gas sands become charged with high pressure from surrounding wells. In such instances, cementing the annulus between strings through a casinghead connection can repair the casing.
The reverse-circulation cementing technique involves pumping the slurry down the annulus and displacing the drilling fluid back up through the casing. The float equipment, differential fill-up equipment, and wellhead assembly must be modified. This method is used when the cement slurry cannot be pumped in turbulent flow without breaking down the weak zones above the casing shoe. Reverse circulation allows for a wider range in slurry compositions, so heavier or more-retarded cement can be placed at the lower portion of casing, and lighter or accelerated cement can be placed at the top of the annulus. Caliper surveys should be made before the casing is run, to determine the necessary volume of cement and minimize overplacement.
Delayed-set cementing involves placing a retarded cement slurry containing a filtration-control additive in a wellbore before running the casing. This method can help to obtain a more uniform sheath of cement around the casing than may be possible with conventional methods.
- The cement is placed by pumping it down the drillpipe and up the annulus.
- The drillpipe is then removed from the well, and casing or liner is sealed at the bottom and lowered into the unset cement slurry.
- After the cement slurry is set, the well can be completed with conventional methods.
Delayed-set cementing application
This technique has been used in tubingless-completion wells by placing the slurry down one string and lowering multiple tubing strings into the unset cement. When the casing is run into the cement slurry, drilling fluid left in the annulus mixes with the cement slurry. Although not ideal, this development is preferred to leaving the drilling fluid in the annulus as a channel or pocket. The delayed-set cement slurry allows protracted reciprocation of the casing string, which is more likely to ensure a uniform cement sheath.
Delayed-set cementing disadvantage
A disadvantage to delayed-set cementing is the increased water/oil-contact (WOC) time, which could be expensive if a drilling rig is kept on location while the cement sets and gains strength. If the drilling rig can be moved off location and a workover rig can complete the well, the cost can be reduced.
Multiple-casing completions are used when single or conventional completions are not economically attractive. When multiple strings are placed in a well, each string is usually run independently, and the longest string is landed first. The first string is set in the hanger and is circulated before the second string is run. After the second string is landed in the hanger, it is circulated while the third string is run. In areas where lost circulation is a known problem, cement can be placed through the longest casing string. Once the cement fill-up has been established, the remainder of the hole is filled with cement slurry through a shorter string.
Centralizers are frequently used, one per joint from 100 ft above to 100 ft below productive zones. Other casing equipment in these small-diameter holes includes landing collars for cement wiper plugs, full-opening guide shoes, and limited-rotating scratchers for single completions. All float equipment, centralizers, and scratchers should be able to pass the hanger assembly in the casinghead.
Other factors considered in the design of cement slurry are similar to those considered in the design of slurry for a single string of pipe. The cement is usually pumped down the longest strings simultaneously, although this is not mandatory. The idle strings may be pressured to 1,000 to 2,000 psi during cementing to safeguard against:
- Thermal buckling
Cementing of high-pressure/high-temperature wells
Recent technological advances have allowed the production of reservoirs that were once considered too expensive and risky to be commercially viable. Designs for these wells must withstand high temperatures and pressures, as well as frequently encountered corrosive gases such as H2S and CO2. Completions performed in high-pressure/high-temperature (HP/HT) reservoirs are some of the most expensive in the industry. High completion costs make it a necessity to successfully cement the well casing on the primary cementing job and eliminate the need for remedial cementing. HP/HT reservoirs are characterized by reservoir depths greater than 15,000 ft, reservoir pressure greater than 15,000 psi, and reservoir-fluid temperatures from 300 to 500°F.
To provide optimum zonal isolation, one should consider not only the primary cementing job, but also the long-term, post-placement effects of various operations that can place stress on the set cement. In the initial cementing, the job should be designed to displace the drilling fluid completely and to prevent gas migration and fluid loss. Once the initial cement job is completed, the effects of stress throughout the well’s life will determine the cement sheath’s future viability.
In most wells, the liner or production string is the most important component. In HP/HT wells, the conductor string can be placed under greater loading and all sections of the well can be exposed to formation, temperature, and pressure changes that are greater than normal; therefore, the well should be examined from the whole-well perspective.
A well’s characteristics determine the cement-slurry properties and performance. A careful and thorough review of these characteristics is essential for designing an effective cement slurry and ensuring correct placement. Engineers should combine individual variables to develop a total-cement-job design.
Guidelines for improving cementing results are:
- Condition the drilling fluid to break its gel structure, thereby reducing its viscosity and improving its mobility.
- Use pipe movement to dislodge pockets of gelled, immobile drilling fluid.
- Use mechanical scratchers and wall cleaners to maximize pipe-movement effectiveness, which can erode excess drilling fluid.
- Centralize pipe in and near “critical” zones. A minimum of 70% casing standoff is recommended. Good pipe standoff helps increase drilling-fluid removal, thereby equalizing forces exerted by cement flowing up the annulus.
- Use the highest possible pump rates to get the greatest displacement efficiency.
- Use spacers and/or flushes to isolate dissimilar fluids and prevent potential contamination problems.
- Use a drilling fluid with a rheology that allows efficient drilling-fluid removal without raising the equivalent circulating density (ECD) to an unacceptable level.
- Use enough spacer and/or flush to allow adequate contact time (7 to 10 minutes contact and 500 to 1,000 ft of annulus).