Function of cementing

In an oil/ gas well, the primary functions of cement are:
1. Provide zonal isolation
2. Support axial load of casing strings
3. Provide casing protection against corrosive fluids
4. Support the wellbore

Cement Manufacture &Chemistry

Cement is made from calcareous and argillaceous rocks such as limestone, clay and shale
and any other material containing a high percentage of calcium carbonate. The dry material
is finely ground and mixed thoroughly in the correct proportions.The chemical composition
is determined and adjusted if necessary. This mix is called the kiln feed.




The kiln feed is then heated to temperatures of around 2600-2800 F (1427-1538 C). The
resulting material is called clinker. The clinker is then cooled, ground and mixed with a
controlled amount of gypsum and other products to form a new product called Portland
cement. Gypsum (CaSO4. 2H2O) is added to control the setting and hardening properties of
the cement slurry and to prevent the flash setting cement. Figure (1) shows a flow diagram
of the manufacturing process and the chemical composition of the clinker.
Cement slurry is the mixture produced when dry cement is mixed with water.

Oil well cement is manufactured to API Specification 10 and is divided into 8 classes (A-H)
depending upon its properties. Class G and H are basic well cements which can be used with
accelerators and retarders to cover a wide range of depths and temperatures. The principal
difference between these two classes is that Class H is significantly coarser than Class G.

The classes are:

• CLASS A: Intended for use from surface to a depth of 6,000 ft (1,830 m), when special
properties are not required. Similar to ASTM (American Society for Testing Materials) Type I
cement.
• CLASS B: Intended for use from surface to a depth of 6,000 ft (1,830 m). Moderate to high
sulphate resistance. Similar to ASTM Type II, and has a lower C3A content than Class A.
• CLASS C: Intended for use from surface to a depth of 6,000 ft (1,830 m) when conditions
require early strength. Available in all three degrees of sulphate resistance, and is roughly
equivalent to ASTM Type III. To achieve high early strength, the C3S content and the surface
area are relatively high.
• CLASS D: Intended for use from 6,000 ft (1,830 m) to 10,000 ft (3,050 m) under conditions of
moderately high temperatures and pressures. It is available in MSR (moderate sulphate resistance)
and HSR (high sulphate resistance) types.
• CLASS E: Intended for use from 10,000 ft (3,050 m) to 14,000 ft (4,270 m) under conditions
of high temperatures and pressures. It is available in MSR and HSR types.
• CLASS F: Intended for use from 10,000 ft (3,050 m) to 16,000 ft (4,880 m) depth under
conditions of extremely high temperatures and pressures. It is available in MSR and HSR types.
• CLASS G + CLASS H: Intended for use as a basic well cement from surface to 8,000 ft (2,440
m) as manufactured, or can be used with accelerators and retarders to cover a wide range of well
depths and temperatures. No additions other than calcium sulphate or water, or both, shall be
interground or blended with the clinker during manufacture of Class G and H well cements.
They are available in both MSR and HSR types.

Cementing additives

Additional chemicals are used to control slurry density, rheology, and fluid loss, or to
provide more specialised slurry properties.
Additives modify the behaviour of the cement slurry allowing cement placement under a
wide range of downhole conditions. There are many additives available for cement and these
can be classified under one of the following categories:
Accelerators: chemicals which reduce the thickening time of a slurry and increase the rate
of early strength development.They are usually use in conductor and surface casing to reduce
waiting on cement time (WOC). Calcium chloride (CaCl2), sodium chloride (NaCl) and sea
water are commonly used as accelerators.
Retarders: chemicals which retard the setting time (extend the thickening) of a slurry to aid
cement placement before it hardens.These additives are usually added to counter the effects
of high temperature.They are used in cement slurries for intermediate and production
casings, squeeze and cement plugs and high temperature wells. Typical retarders include:
sugar; lignosulphonates, hydroxycarboxylic acids, inorganic compounds and cellulose
derivatives. Retarders work mainly by adsorption on the cement surface to inhibit contact
with water and elongate the hydration process; although there are other chemical
mechanisms involved.
Extenders: materials which lower the slurry density and increase the yield to allow weak
formations to be cemented without being fractured by the cement cloumn.Examples of
extenders include: water, bentonite, sodium silicates, pozzlans, gilsonite, expanded perlite,
nitrogen and ceramic microspheres.
Weighting Agents: materials which increase slurry density including barite and haematite,
see Chapter Seven for full description.
Dispersants: chemicals which lower the slurry viscosity and may also increase free water by
dispersing the solids in the cement slurry. Dispersants are solutions of negatively charged
polymer molecules that attach themselves to the positively charges sites of the hydrating
cement grains.The result is an increased negative on the hydrating cement grains resulting in
greater repulsive forces and particle dispersion.
Fluid-Loss Additives: Excessive fluid losses from the cement slurry to the formation can
affect the correct setting of cement. Fluid loss additives are used to prevent slurry
dehydration and reduce fluid loss to the formation.Examples include: cationic polymer, nonionic
synthetic polymer, anionic synthetic polymer and cellulose derivative.
Lost Circulation Control Agents: materials which control the loss of cement slurry to weak
or fractured formations.

Strength Retrogression: At temperatures above 230 F, normal cement develop high
permeability and reduction in strength. the addition of 30-40% BWOC (by weight of
cement) silica flour prevents both strength reduction and development of permeability at
high temperatures.
Miscellaneous Agents: e.g. Anti-foam agents, fibres, latex.

Slurry testing

Cement tests should always be performed on representative samples of cement, additives
and mix water as supplied from the rig. Cement tests are detailed in API 10, references a & b.1 1-THICKENING TIME
Thickening time tests are designed to determine the length of time which a cement slurry
remains in a pumpable state under simulated wellbore conditions of temperature and
pressure. The pumpability, or consistency, is measured in Bearden Consistency units (Bc);
each unit being equivalent to the spring deflection observed with 2080 gm-cm of torque
when using the weight-loaded type calibration device. The measure takes no account of the
effect of fluid loss. Thus, thickening times in the wellbore may be reduced if little, or no,
fluid loss control is specified in the slurry design.
Results should quote the time to reach 70 Bc - generally considered to be the maximum
pumpable consistency.
2- FREE WATER AND SEDIMENTATION
The separation of water from a slurry, once it has been placed, can lead to channel formation
and gas migration problems - particularly in deviated wells. The free-water test is designed
to simulate this using a 250 ml graduated cylinder in which slurry is left to stand for two
hours under simulated wellbore conditions. The volume of water collected after this period is
expressed as a percentage by volume.
For deviated wellbores, a more critical test is to incline the column at 45 degrees. However,
care should be exercised with the results from inclined tests as the migration path for the
water is significantly reduced and thus the free water measured will increase. Downhole, this
may not be the case due to the presence of the casing string.
The reporting of free-water should be as a percentage. When 'traces' are reported, definition
of this term should be sought. For liners and in wells where gas may be present, a zero freewater
slurry should be used.
The amount of sedimentation of the slurry should also be reported by measurement of the
variation of density over a sectioned column of set cement.
3- FLUID-LOSS
Fluid-loss tests are designed to measure the slurry dehydration during, and immediately after
cement placement. Under simulated wellbore conditions, the slurry is tested for filtrate loss
across a standardised filter press at differential pressures of 100 psi or 1000 psi. The test
duration is 30 minutes and results are quoted as ml/30 min.
4 -COMPRESSIVE STRENGTH
The measurement of the uniaxial compressive strength of two-inch cubes of cement provides
an indication of the strength development of the cement at downhole conditions. The slurry
samples are cured for 8, 12, 16 and 24 hours at bottom-hole temperatures and pressures and
the results reported in psi. Dynamic measurements using ultrasonic techniques correlate well
with API test results, but can lead to over-estimation of the strength.
5- RHEOLOGY
Ensuring that the rheological behaviour of the slurry downhole is similar to that specified in
the design is essential for effective cement placement. The slurry viscosity is measured using
a rotational viscometer, such as a Fann. The slurry sample should be conditioned for 20
minutes in an atmospheric consistometer before measurements are taken.
Readings should be taken at ambient conditions and at BHCT when possible. Measurements
should be limited to a maximum speed of 300 rpm (shear rate 511 1/s). Readings should also
be reported at 200, 100, 60, 30, 6 and 3 rpm.

Types of casing

Types of casing

In practice, it would be much cheaper to drill a hole to total depth (TD), probably with a
small diameter drill bit, and then case the hole from surface to TD. However, the presence of
high-pressured zones at different depths along the wellbore, and the presence of weak,
unconsolidated formations or sloughing, shaly zones, necessitates running casing to seal off
these troublesome zones and to allow the drilling to TD. Thus, different sizes of casing are
employed and this arrangement gives a tapered shape to the finished well.
The types of casing currently in use are as follows:

1. Stove Pipe

Stove pipe (or marine-conductor, or foundation-pile for offshore drilling) is run to prevent
washouts of near-surface unconsolidated formations, to provide a circulation system for the
drilling mud and to ensure the stability of the ground surface upon which the rig is sited. This
pipe does not usually carry any weight from the wellhead equipment and can be driven into
the ground or seabed with a pile driver. A typical size for a stove pipe ranges from 26 in. to
42 in.

2. Conductor Pipe
 
Conductor pipe is run from the surface to a shallow depth to protect near surface
unconsolidated formations, seal off shallow-water zones, provide protection against shallow
gas flows, provide a conduit for the drilling mud and to protect the foundation of the
platform in offshore operations. One or more BOPs may be mounted on this casing or a
diverter system if the setting depth of the conductor pipe is shallow. In the Middle East, a
typical size for a conductor pipe is either 18 5/8 in. (473 mm) or 20 in. (508 mm). In North
Sea exploration wells, the size of the conductor pipe is usually 26 or 30 in.
Conductor pipe is always cemented to surface. It is used to support subsequent casing strings
and wellhead equipment or alternatively the pipe is cut off at the surface after setting the
surface casing. In offshore operations, conductor pipes are either driven by a hammer or run
in a drilled hole or run by a combination of drilling and driving especially where hard
boulders are encountered near seabed.

3. Surface Casing

Surface casing is run to prevent caving of weak formations that are encountered at shallow
depths. This casing should be set in competent rocks such as hard limestone. This will ensure
that formations at the casing shoe will not fracture at the high hydrostatic pressures which
may be encountered later. The surface casing also serves to provide protection against
shallow blowouts, hence BOPs are connected to the top of this string. The setting depth of
this casing string is chosen so that troublesome formations, thief zones, water sands, shallow
hydrocarbon zones and build-up sections of deviated wells may be protected. A typical size
of this casing is l3 3/8 in. (240 mm) in the Middle East and 18 5/8 in. or 20 in. in North Sea
operations.

4. Intermediate Casing

Intermediate casing is usually set in the transition zone below or above an over-pressured
zone, to seal off a severe-loss zone or to protect against problem formations such as mobile
salt zones or caving shales. Good cementation of this casing must be ensured to prevent
communication behind the casing between the lower hydrocarbon zones and upper water
formations. Multistage cementing may be used to cement this string of casing in order to
prevent weak formations from being subjected to high hydrostatic pressure from a
continuous, long column of cement. The most common size of this casing is 9 5/8 or 10 ¾ in.

5. Production Casing

Production casing is the last casing string. It is run to isolate producing zones, to provide
reservoir fluid control and to permit selective production in multizone production. This is the
string through which the well will be completed. The usual sizes of this string are 4 1/2, 5 and
7 in.


6. Liners
A liner is a string of casing






that does not reach the surface. Liners are hung on  the intermediate casing by
use of a liner-hanger. In liner completions both the liner and the intermediate
casing act as the production string. Because a liner is set at the bottom and hung from
the intermediate casing, the major design criterion for a liner is usually the ability to withstand the maximum expected collapse pressure.

TYPES OF LINERS

1. Drilling liners are used to isolate lost circulation or abnormally pressured zones to
permit deeper drilling.
2. Production liners are run instead of a full casing to provide isolation across the
production or injection zones.
3. The tie-back liner is a section of casing extending upwards from the top of an
existing liner to the surface. It may or may not, be cemented in place.
4. The scab liner is a section of casing that does not reach the surface. It is used to
repair existing damaged casing. It is normally sealed with packers at top and bottom
and, in some cases, is also cemented.
5. The scab tie-back liner is a section of casing extending from the top of an existing
liner but does reach the surface. The scab tie-back liner is normally cemented in
place.

 ADVANTAGES OF A LINER

The main advantages of a production liner are: (a) total costs of the production string are
reduced, and running and cementing times are reduced; (b) the length of reduced diameter is
reduced which allows completing the well with optimum sizes of production tubings.
Other advantages include:
• Complete wells with less weight landed on wellheads and surface pipe
• A scab liner tie-back provides heavy wall cemented section through salt
sections.
• Permits drilling with tapered drillstring.
• Where rig capacity cannot handle full string; when running heavy 9 5/8" casing.
• To provide a PBR (Polished Bore Receptacle) completion. This type of
completion is recognised to be the best casing to tubing seal system.
• Improved completion flexibility.
• To provide an upper section of casing (tie-back liner) which had seen no
drilling.
• For testing in critical areas where open hole testing is not practised.

The disadvantages of a liner are:

(a) possible leak across a liner hanger; and
(b) difficulty in obtaining a good primary cementation due to the narrow annulus between
the liner and the hole.