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CEMENTING
packer to isolate the squeeze area from the rest of the
well. This method enables closer control of the entire
squeeze cementing process and permits a more efficient
placement of the cementing slurry into targeted zone.
• Top-down annular casing squeeze method is typically
used to force cement to surface when it failed to do so
during the primary cement job. These squeeze jobs are
normally performed by pumping cement down the casing
annulus by an outer casing valve or installing a small
tubing string into the targeted annuli and pumping cement
through this tubing. Monitoring the pressure of the inner
casing pressure and the annular pressure in which the
cement is being pumped is necessary to prevent casing
damage caused by collapse (inner casing) or rupture
(outer casing).
Job design
To design an effective cement squeeze plan, the well operator generally works with the cementing service provider to
select the casing packer type, cement placement method
(hesitation, stage or continuous pumping) and the cement
slurry design. To make their selections, well operators and
cement service providers use several variables:
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Common squeeze cementing packers:
• Squeeze-cementing casing packers (tools) are used to
control the placement of job fluids and isolate wellbore
pressures during cement squeeze operations. Squeezecement packers are classified as either drillable or
retrievable. The type of packer used is dependent on the
squeeze job objective(s), casing and tubing condition, and
formation parameters.
• Drillable-casing packers (retainers) are designed and
manufactured to be drilled out of the casing when
required. Drillable casing packers can be set using
conventional work strings in compression or tension, or
by electric wireline operations. These tools typically
incorporate a “sliding” or “poppet” valve, which closes
when the work-string stinger is pulled out of the retainer
following the squeeze job. The retainer contains the
pressure below, which is beneficial in many cement
squeeze operations.
• Retrievable-squeeze packers are designed and
manufactured using high-strength steel to provide a
higher pressure rating than drillable casing packers. These
retrievable packers also feature a fluid bypass system,
which reduces formation surge and swab pressure events
during installation and removal from the well. Additionally,
the packers have mechanical and hydraulic casing slips,
which anchor the packer to the casing wall. And, because
they have a larger internal diameter, casing perforating
tools and other diagnostic tools can be used during well
operations. Since these packers feature high-strength
steel, fluid circulation ports and casing slips, it is very
important to monitor fluid volumes, casing and work
string pressures, and pipe movement during operations to
prevent the these packers from becoming “stuck” in the
well. Removal of “stuck” retrievable squeeze packers
usually requires extensive milling, which if unsuccessful
may result in loss of the wellbore section or even the
entire well.
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Job objective;
Well and operational risk and safety;
Well operations and production history;
Casing size, age and pressure rating;
Drillpipe or tubing size and pressure rating;
Formation properties;
• Pore pressure;
• Permeability;
• Fracture gradient;
• Fluids types (oil, gas, water, combination);
Diagnostic logs (Cement bond, temperature, noise);
Well fluids and type;
Rig capabilities;
Field history and previous squeeze job results.
Plug cementing
Plug cementing is another remedial cementing technique
and refers to the method of placing the cement slurry into
the wellbore to create a solid wellbore seal or “plug”. The
general plug cementing process involves selecting the location for the plug, positioning the end of the work string at
the bottom of the desired plug depth, mixing and pumping
a cement slurry down the work string (drillpipe or tubing)
into the wellbore, removing the work string from the cement
column and allowing the cement slurry to harden in the wellbore.
Applications
Well or zone abandonment:
• Seal a dry hole;
• Seal depleted zones;
• Seal non-commercial zones or wellbores;
• Temporary well or zone abandonment.
Zonal isolation or well stability:
• Isolate one pressure zone from another;
• Prevent zonal fluid communication;
• Stop lost circulation events;
• Enable drilling through fracture or weak formations.
Directional drilling (kick-off plugs):
• Support controlled changes in well trajectory (whipstock
operations);
• Sidetrack operators around a “fish”.
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Formation testing:
• Creates a base for open-hole formation test tools.
Common plug techniques
Listed below are the four most frequently used cement plug
placement methods:
• Balanced-plug method is the most often used method to
install or set a cement plug in the wellbore. It works by
means of the “balanced hydrostatic pressures” concept.
“Balanced” describes a condition in which the top of
cement and spacer outside the work string are at the
same height as the top of cement inside the work string at
the end of pumping. To help achieve this balance, it is
important that the well is in a fluid static state, the
wellbore and drilling mud are prepared to receive cement,
the spacers/flushes volumes and densities meet design
requirements and the cement slurry is designed to ensure
safe cement placement and removal of the work string.
Rig operations should be prepared to begin removing
(pulling) the work string from the cement at the design
rate as soon as the cement is in place and surface pressure
has been released.
• Two-plug method uses wiper plugs or rubber balls to
isolate the cement from well fluids (prevent contamination)
in the drillpipe and provide positive surface pressure
events, which are used as an indication of cement
placement in the wellbore. Once the lead cement spacer
or flush has been pumped into the work string, the bottom
wiper plug or ball is released into the work string, the
cement volume is mixed and pumped, the top wiper plug/
rubber ball is released and drilling mud is used to displace
the cement. When the bottom plug/ball lands in a
receiving tool, a positive surface event occurs that
indicates the position of the leading edge of the cement
slurry. Additional surface pressure is applied to release
the bottom wiper plug/ball, enabling the cement to be
pumped into place. The top wiper plug lands in the wiper
plug/ball receiving tool, indicating that cement is in place.
Surface pressure is then applied, causing the top wiper
plug/ball to be sheared out of the tool, which reestablishes work string circulation. The work string is then
pulled from the cement column at the designed rate; rig
operations should be prepared to conduct this step as
soon as the cement is in place and surface pressure has
been released.
• Dump bailer method incorporates the use of a cylindrical
fluid container, which is run into the well with wireline.
When the bottom of the dump bailer reaches the desired
depth, an electrical or mechanical trigger is used to open
the bottom of the cylindrical fluid container, thereby
releasing the cement slurry into the well bore. Typically,
this method requires multiple runs, because fluid
container’s limited capacity.
• Mechanically supported plug method is a variation of the
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balance plug method that incorporates a mechanical tool
to provide a bottom for the cement column and prevent
migration of the cement column down the wellbore. This
method allows for a choice of several mechanical tools:
inflatable packers, cement baskets, tools that use
expandable membranes, which open when positioned in
the wellbore. Once the mechanical tool is in the wellbore
at the designed depth, the work string is positioned above
the tool and the balance plug or two-plug method is used
to place the cement column in the wellbore.
Job Design
When designing a cement plug that will meet the required
objectives, the well operator will work with the cementing
service provider to select the appropriate plug setting technique and the cement slurry design. To formulate a design
operators and cement service providers consider a number
of variables:
• Job objective;
• Well and operational risk and safety;
• Well operations history;
• Casing size, age and pressure rating;
• Hole size and hole enlargement;
• Well stability;
• Drillpipe or tubing size and pressure rating;
• Cement plug setting tools;
• Well fluids and type;
• Rig capabilities;
• Field history and previous plug job results;
• Hole angle.
Lost circulation cement squeezes and plugs
In some cases, controlling lost circulation during drilling operations may call for a cement squeeze or plug job to minimize or stop drilling fluid losses and help regain full returns
of the circulation fluids to surface. The formation interval
into which fluids are lost is commonly called the “thief zone.”
Losses may be halted and well circulation restored by spotting a cement plug across the thief zone and, after waiting on
cement (WOC), drilling back through the plug. This operation can sometimes be less costly than a squeeze-cement
job. Spotting plug cement in open-holes across thief zones
with smaller diameter tubing has the advantage of less
risk for drillpipe sticking issues and better cement placement. The tubing is often called a “stinger pipe” which can
be installed below the drillpipe. However, many plug and
squeeze-cement jobs are pumped “through the bit” due to
the time required to trip out and back into the well with a
lost-circulation treatment bottomhole assembly (BHA).
Low-pressure or depleted “thief zones” that steal well fluids
drilling fluids can sometimes be sealed by a squeeze-cementing job. In severe cases, more than one job may be
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required. A combination squeeze-and plug-cementing job
may be needed when losses occur after drilling out the casing shoe. This can sometimes improve cement placement
in the annulus between the open hole and the shoe track
including some distance above the shoe track. For deeper
thief zones, drillpipe is pulled up above the top of the cement
plug and, if needed, above the open-hole; applying squeeze
pressure at this stage will force some plug cement into the
thief zone. By placing the end of the drillpipe inside the casing shoe, the risk of stuck drill pipe can be eliminated.
Cementing through the bit
Conducting cementing operations when a drill bit is in the
well, is a very high risk operation and requires an additional
level of pre-job planning including both Job Safety Analysis
(JSA) and risk assessments. When precautions were taken,
cement slurries have been successfully pumped through the
drilling BHA, including motors, without prematurely setting.
One key condition for successful jobs is making sure the
hole (motor, BHA, DP, annulus, etc.) is cooled by circulating
enough drilling fluid. The BHA tools temperature readings
should be used for test temperatures used in cement’s laboratory thickening time tests. When no temperature data is
available, thermal modeling computer software can be run
to determine how long it takes the circulating drilling fluid
to cool the recently drilled “hot” hole section and BHA. The
start of the cement squeeze or plug job can then be delayed
until the hole and BHA (motor, etc.) is cool enough to prevent shorter than designed pump times. When needed, add
retarder in the cement slurry based on lab testing with higher temperatures.
Other recommendations are listed below:
1. Total bit nozzle flow area and other flow restrictions in the
BHA should be sufficient for the designed pump rate and
is sometimes specified to be greater than 0.5 sq. in.;
2. The backside surface pressure is continuously monitored
to check if cement is circulated up the annulus. This is
intended for placing plug cement, but not for squeezing
cement;
3. For shoe squeezes, the bit and BHA are spotted inside the
last string of casing one or two pipe stands above the
shoe;
4. Open hole squeezes to control lost circulation, place the
bit one or two pipe stands above the lost circulation zone.
5. Run a lab-tested, compatible spacer ahead and behind the
cement slurry. Spacer volumes are determined based on
conditions;
6. Do not stop pumping with cement inside the drill pipe
(DP). When the spacer reached the bit, close the choke
manifold to begin bullheading cement into the zone of
interest;
7. A DP swivel is installed above the rotary table and DP is
rotated either intermittently or continuously to check for
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any increase in TOB that may indicate that cement is in
the annulus;
8. If TOB increases during the job, further action is taken to
keep the DP free such as immediately PU one stand and
check that TOB decreases before continuing the squeeze.
9. If TOB doesn’t decrease and hook load increased during
PU, immediately shut down the squeeze and take further
action such as POOH to prevent planting DP;
10.After all cement slurry has cleared the DP, pull five stands
or 500 ft of DP and continue checking TOB;
11. When the designed squeeze pressure is achieved,
circulate drilling fluid to clear the annulus of any cement
slurry. Continue to WOC until cement is set and rig is
ready to continue drilling operations.
Preparing the well and wellsite
for cementing
Pre-job meeting
The service company supervisor should hold a pre-job
meeting with his crew, the rig crew and all other involved
personnel in cementing the well to review responsibilities
and coordinate the operations to be performed. Safety
should always be the top priority.
That meeting may cover a number of topics:
• Roles and responsibilities - It is important that everyone
involved understand their role during the cement job;
open communication is essential. The pre-job meeting is
a means to establish everyone’s role and to discuss
potential risks and contingency plans to deal with any
issue that may develop.
• Rigging-up and pressure testing of treatment lines should
be discussed.
• Job procedure – Every step of the cement job should be
covered. Volume calculations of cement, mix water,
displacement, expected pit gains should have been
independently verified by at least two members of the
team. The pressure to bump the plug calculation should
also be independently verified. Depending on job
specifics, there may be other pressure, volume or rate
calculations that need to be performed and verified before
the job. Equipment and material checks should be also be
independently verified by two or more people.
• Potential events to discuss – Unplanned issues include
lost circulation, excess gas, well control issues, equipment
failures, abnormally high or low pump pressure limits,
slow mixing rates, cement volume shortages, lack of
cement density control, failure of plug to bump on time
and floats to hold.
• Contingency plans – Circulating the job out and starting
over criteria and switching from cement pumps to rig
pumps in order to circulate out, dropping the top plug and
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displacing without pumping the planned job volume and a
complete list of standby equipment on site.
• Weather conditions – Considerations include how
extreme heat, cold, or offshore sea state conditions might
affect personnel, equipment and materials. Extreme
temperatures may introduce conditions different from the
cement job’s design conditions (ambient) that could
cause compromise the job. For example, in the Middle
East, on several occasions cement has prematurely set
inside the batch mixer as a result of prepumping and
variance in ambient temperature used by the design from
lab: 120-140°F. The possibility of these effects should be
discussed together with measures to mitigate the adverse
effects of extreme weather conditions.
Preparing the well for cementing
Hole and mud conditioning for cementing operations should
begin prior to tripping the drillstring out of the hole for the
purpose of running casing. While the wellbore may be clean
enough to enable trouble-free tripping operations, the presence of cuttings beds, fill on bottom, or mud with undesirable properties make running and cementing casing difficult.
Even though the well will need to be circulated and conditioned again after casing is run to bottom, the hole should
be clean and the drilling fluid should have the desired mud
properties before casing is run.
The drilling program should outline the hole-cleaning procedures to be followed for each hole section. The procedures
should specify guidelines for flow rate, pipe reciprocation,
pipe rotation, cuttings and gas monitoring as well as drilling fluid property specifications. Hole cleaning practices will
differ between vertical or near vertical wells, and extended
reach high-angle or horizontal wells. For wells with greater
than 30° to 40° of inclination, torque-and-drag monitoring
is recommended to help determine when the hole is clean.
Torque-and-drag can be monitored by using work string
pick-up and slack-off weight indicator readings and rotating
torque measurements. Torque-and-drag monitoring can be
used during hole cleaning and tripping operations to gauge
the quality of the hole. This applies to tripping the drillstring
or casing.
Hole and mud conditioning becomes imperative in the following situations:
• Liner cement jobs run with tight tubular/annular
clearances, when the liner hanger is set the annular flow
path becomes more restricted and prone to plugging with
cuttings, debris or gelled mud;
• All wells with tight annular clearances;
• Wellbores with small mud weight margins between the
minimum mud weight needed to control formation
pressure and the mud weight that results in mud losses to
the formation, resulting in loss of returns caused by
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bridging or plugging off with cuttings in tight clearances,
and high equivalent circulating density (ECD) from the
frictional pressure drop while circulating;
• During casing or liner running, surge and swab pressures
can result in losses or formation fluid influxes if the
tripping speed is not controlled. The drilling program
should specify the running speed to minimize surge
effects. Computer programs are available to aid ECD
management and to determine the proper tripping speed
to minimize surge and swab forces. In very close-tolerance
situations, “auto-fill” float equipment can be used to
minimize surge pressures by allowing mud to flow up the
inside of the casing while casing is run in the well. The
“auto-fill” float equipment can be converted to
conventional float equipment when needed. Surge
pressures can also be minimized by controlling the mud
properties so that they have non-progressive gel strengths
and overall viscosity readings as low as practical for hole
cleaning. Depending on well conditions, the well should
be circulated at prescribed intervals while running in the
hole to help break gel strengths and ensure the well is
stable.
Hole conditioning with casing on bottom
Once casing is on bottom, the well should be circulated until
well conditions are stable and the wellbore is free of excess
gas. Mud properties in and out should be the same and within specifications. Between bottoms-up and the casing volume, a minimum of the larger of the two should be pumped.
Pumping a minimum of one casing volume will indicate if
there are any foreign objects in the casing that might plug up
the float equipment. Pumping bottoms-up will reveal if there
have been any influxes into the well during casing running
operations. Other factors that may need to be considered
for circulating with casing on bottom are the need to cool the
wellbore down, cleaning the wellbore of cuttings and maintaining the optimum rheology for mud removal by cement.
In general, the pump rate should be as fast as possible without inducing lost circulation.
Rig personnel support of cementing operations
Drilling rig personnel may be assigned a number of cementing operation support activities:
• Identifying the location of mix water, drilling mud or both
supply lines that furnish cementing equipment (cement
pump/batch mixer) with mix water and drilling mud;
• Ensuring there is sufficient cement mix water, drilling mud
or both to mix and displace the cement and communicating
and facilitating the method of fluid transfer (centrifugal
pump, gravity feed, etc.);
• Identifying the barite supply lines that furnish cementing
equipment (cement pump/batch mixer) with bulk barite
– typically for spacers;
• Facilitating the movement of liquid additives (drums,
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totes, etc.) from the storage area to the liquid additive
system and the pneumatic transfer of cement from the rig
tanks to the cementing unit during cementing operations
that take place offshore or at remote sites;
• Informing the cementing service providers of any
restrictions on the placement of the cementing equipment
on location;
• Monitoring returns at surface for change in flow rates and
presence of pumped fluids (spacer and cement slurry)
and diverting contaminated fluids from the active system;
• Many operations require the rig pump to take over
displacement – in this case rig personnel should coordinate
closely with cementing personnel regarding volumes,
rates and returns.
Rig personnel should be cautious when working in or near
the cement pumping unit, cement bulk equipment, liquid
additive systems, process controls, batch mixers, flow/mass
meters, densitometers, temporary bulk/liquid transfer lines,
bulk manifolds and electronic cabling. Rig personnel should
always be aware of the location and service state (not in service, pressure testing, in operation, etc.) of the high pressure
discharge iron from the cementing unit to the rig floor as
well as the status of pressurized bulk tanks, lines and hoses.
During foamed cementing operations, care should be exercised around the cryogenic nitrogen storage tanks, nitrogen
pumps and nitrogen discharge/vent lines.
Cement dust
Well cementing operations utilizes equipment designed to
prevent the escape of cement dust into the atmosphere.
However, in the event that personnel are exposed to `cement dust, hazard mitigation procedures are used to prevent
injuries or health issues. Local regulators may publish these
procedures to help prevent HSE incidents and require them
to be posted on bulletin boards or included in the rig’s safety
manuals at the wellsite. For example, the U.S. Occupational
Safety and Health Administration’s (OHSA) guidelines are
shown below:
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Hazard: Exposure to cement dust can irritate eyes,
nose, throat and the upper respiratory system. Skin
contact may result in moderate irritation to thickening/
cracking of skin to severe skin damage from chemical
burns. Silica exposure can lead to lung injuries including
silicosis and lung cancer.
Solutions:*
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Rinse eyes with water if they come into contact with cement dust and consult a physician;
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Use soap and water to wash off dust to avoid skin damage;
* Reference: OSHA 3221-12N 2004
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Wear a P-, N- or R-95 respirator to minimize inhalation
of cement dust;
Eat and drink only in dust-free areas to avoid ingesting
cement dust.
Rig personnel may also provide support in the preparation
of washes or spacers used in the cementing operation. The
mixing of spacer fluids should be conducted using instructions provided by the cementing service company or, in the
case of more complex spacer systems, under the direct supervision of the service company personnel. Rig personnel
should always be mindful of the exposure and respiratory
hazards associated with the handling and mixing of materials used to prepare washes and spacers. As such, rig personnel involved in the mixing of spacer fluids should always
abide by the same personal protection equipment requirements as those used by the cementing service provider.
Mixing cement slurry during the cementing operation is the
responsibility of the cementing service company. However,
rig personnel may be asked to provide assistance to the cementing service supervisor or other cementing personnel on
certain occasions:
• Assisting the cementing service providers with obtaining
samples of cement slurry, bulk materials and liquid
additives;
• Providing a tally of materials being consumed, additives,
mix water, etc;
• Managing fuel and air supply for cementing equipment
and ensuring that the air supply is dry;
• Helping the cementing service company manage the rig
bulk material supply system;
• Measuring and recording slurry density using pressurized
mud balance;
• Assisting in efforts to repair cementing equipm
Rigging up and pressure testing treatment lines
In preparing for cementing and pumping operations, service company personnel rig up and use a high- pressure
treatment line often referred to as a cement service line.
They may ask the rig crew to assist them in this operation.
High-pressure pumping requires managing hazards and
risk. In addition, all personnel must comply with local regulations. Examples can be found under OHSA rules in North
America, DNV in Norway or ANP in Brazil.
Components of a high-pressure line
• Chiksan/swivel joint is a high pressure articulating
hardline used to make connections adjustable by rotating
and a swiveling them. A double chiksan enables an easier
rig up for spacing and flexibility, regarding vibrations and
pump pulsations during operations.
• Pressure relief (pop-off) valve is a safety device that
protects contained systems from over pressuring. In most
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