The standard slurry densities shown in Table 2 may have to be altered to meet specific operational requirements (e.g. a low strength formation may not be able to support the hydrostatic pressure of a cement slurry whose density is around 15 ppg). The density can be altered by changing the amount of mixwater or using additives to the cement slurry. Most slurry densities vary between 11 – 18.5 ppg. It should be noted that these densities are relatively high when the normal formation pore pressure gradient is generally considered to be equivalent to 8.9 ppg. It is generally the case that cement slurries generally have a much higher density than the drilling fluids which are being used to drill the well. The high slurry densities are however unavoidable if a hardened cement with a high compressive streng this to be achieved.

table 2

The thickening time of a cement slurry is the time during which the cement slurry can be pumped and displaced into the annulus (i.e. the slurry is pumpable during this time). The slurry should have sufficient thickening time to allow it to be:
• Mixed
• Pumped into the casing
• Displaced by drilling fluid until it is in the required place

Generally 2 – 3 hours thickening time is enough to allow the above operations to be completed. This also allows enough time for any delays and interruptions in the cementing operation. The thickening time that is required for a particular operation will be carefully selected so that the following operational issues are satisfied:
• The cement slurry does not set whilst it is being pumped
• The cement slurry is not sitting in position as a slurry for long periods, potentially being contaminated by the formation fluids or other contaminants
• The rig is not waiting on cement for long periods.

Wellbore conditions have a significant effect on thickening time. An increase in temperature, pressure or fluid loss will each reduce the thickening time and these conditions will be simulated when the cement slurry is being formulated and tested in the laboratory before the operation is performed.


The casing shoe should not be drilled out until the cement sheath has reached a compressive strength of about 500 psi. This is generally considered to be enough to support a casing string and to allow drilling to proceed without the hardened cement sheath, disintegrating, due to vibration. If the operation is delayed whilst waiting on the cement to set and develop this compressive strength the drilling rig is said to be “waiting on cement” (WOC). The development of compressive strength is a function of several variables, such as: temperature; pressure; amount of mixwater added; and elapsed time since mixing.

The setting time of a cement slurry can be controlled with chemical additives, known as accelerators. Table 3 shows the compressive strengths for different cements under varying conditions.

table 3



The water which is used to make up the cement slurry is known as the mixwater. The amount of mixwater used to make up the cement slurry is shown in Table 2.  These amounts are based on :
• The need to have a slurry that is easily pumped.
• The need to hydrate all of the cement powder so that a high quality hardened cement is produced.
• The need to ensure that all of the free water is used to hydrate the cement powder and that no free water is present in the hardened cement.

The amount of mixwater that is used to make up the cement slurry is carefully controlled. If too much mixwater is used the cement will not set into a strong, impermeable cement barrier. If not enough mixwater is used :
• The slurry density and viscosity will increase.
• The pumpability will decrease
• Less volume of slurry will be obtained from each sack of cement

The quantities of mixwater quoted in Table 2 are average values for the different classes of cement. Sometimes the amount of mixwater used will be changed to meet the specific temperature and pressure conditions which will be experienced during the cement job.

table 2

There are other, non-API, terms used to classify cement. These include the following:

• Pozmix cement – This is formed by mixing Portland cement with pozzolan (ground volcanic ash) and 2% bentonite. This is a very lightweight but durable cement. Pozmix cement is less expensive than most other types of cement and due to its light weight is often used for shallow well casing cementation operations.

• Gypsum Cement – This type of cement is formed by mixing Portland cement with gypsum. These cements develop a high early strength and can be used for remedial work. They expand on setting and deteriorate in the presence of water and are therefore useful for sealing off lost circulation zones.

• Diesel oil cement – This is a mixture of one of the basic cement classes (A, B, G, H ), diesel oil or kerosene and a surfactant. These cements have unlimited setting times and will only set in the presence of water. Consequently they are often used to seal off water producing zones, where they absorb and set to form a dense hard cement.

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There are several classes of cement powder which are approved for oilwell drilling applications, by the American Petroleum Institute – API. Each of these cement powders have different properties when mixed with water. The difference in properties produced by the cement powders is caused by the differences in the distribution of the four basic compounds which are used to make cement powder; C3S, C2S, C3A, C4AF (Table 1).

table 1

Classes A and B – These cements are generally cheaper than other classes of cement and can only be used at shallow depths ,where there are no special requirements. Class B has a higher resistance to sulphate than Class A.

Class C – This cement has a high C3S content and therefore becomes hard relatively quickly.

Classes D,E and F – These are known as retarded cements since they take a much longer time to set hard than the other classes of cement powder. This retardation is due to a coarser grind. These cement powders are however more expensive than the other classes of cement and their increased cost must be justified by their ability to work satisfactorily in deep wells at higher temperatures and pressures.

Class G and H – These are general purpose cement powders which are compatible with most additives and can be used over a wide range of temperature and pressure. Class G is the most common type of cement and is used in most areas. Class H has a coarser grind than Class G and gives better retarding properties in deeper wells.

There are many reasons for using cement in oil and gaswell operations. As stated above, cement is most widely used as a seal between casing and the borehole, bonding the casing to the formation and providing a barrier to the flow of fluids from, or into, the formations behind the casing and from, and into, the subsequent hole section (Figure 1). However, when placed between the casing and borehole the cement may be required to perform some other tasks. The most important functions of a cement sheath between the casing and borehole are:

•  To prevent the movement of fluids from one formation to another or from the formations to surface through the annulus between the casing and borehole.
•  To support the casing string (specifically surface casing)
•  To protect the casing from corrosive fluids in the formations.

primary cementing

However, the prevention of fluid migration is by far the most important function of the cement sheath between the casing and borehole. Cement is only required to support the casing in the case of the surface casing where the axial loads on the casing, due to the weight of the wellhead and BOP connected to the top of the casing string, are extremely high. The cement sheath in this case prevents the casing from buckling.

The loads to which the casing will be exposed during the life of the well will depend on the operations to be conducted: whilst running the casing; drilling the subsequent hole section; and during the producing life of the well. These operations will result in radial (burst and collapse) and axial (tensile and compressive) loads on the casing strings. Since the operations conducted inside any particular string (e.g. the surface string) will differ from those inside the other strings (e.g. the production string) the load scenarios and consequent loads will be specific to a particular string. The definition of the operational scenarios to be considered is one of the most important steps in the casing design process and they will therefore generally be established as a company policy.

Liners are run on drillpipe with special tools which allow the liner to be run, set and cemented all in one trip (Figure 12). The liner hanger is installed at the top of the liner. The hanger has wedge slips which can be set against the inside of the previous string. The slips can be set mechanically (rotating the drillpipe) or hydraulically (differential pressure). A liner packer may be used at the top of the liner to seal off the annulus after the liner has been cemented. The basic liner running procedure is as follows:

(a)    Run the liner on drillpipe to the required depth;
(b)    Set the liner hanger;
(c)    Circulate drilling fluid to clean out the liner;
(d)    Back off (disconnect) the liner hanger setting tool;
(e)    Pump down and displace the cement;
(f)    Set the liner packer;
(g)    Pick up the setting tool, reverse circulate to clean out cement and pull out of hole.

casing liner

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After the casing is run to the required depth it is cemented in place while suspended in the wellhead. The method used for landing the casing will vary from area to area, depending on the forces exerted on the casing string after the well is completed. These forces may be due to changes in formation pressure, temperature, fluid density and earth movements (compaction). These will cause the casing to either shrink or expand, and the landing procedure must take account of this. There are basically 3 different ways in which the casing can be cemented and landed:

1. landing the casing and cementing;
2. suspending the casing, conducting the cement job and then applying
3. additional tension when the cement has hardened;
4. landing the casing under compression;

The first case does not require any action after the cementing operation is complete.The casing is simply landed on a boll-weevil hanger and cemented in place. Additional tension (over and above the suspended weight) may however have to be applied to the casing to prevent buckling due to thermal expansion when the well is producing hot fluids. Additional tension can be applied, after the casing has been cemented, by suspending the casing from the elevators during the cementing operation and then applying an overpull (extra tension) to the casing once the cement has hardened.

The casing would then be landed on a slip and seal assembly. The level of overpull applied to the casing will depend on the amount of buckling load that is anticipated due to production. The third option may be required in the case that the suspended tension reduces the casing’s collapse resistance below an acceptable level. In this case the casing is suspended from the elevators during cementing and then lowered until the desired compression is achieved before setting the slip and seal assembly.

Institute of Petroleum Engineering, Heriot-Watt University