ZONAL ISOLATION

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12. ZONAL ISOLATION

12. ZONAL ISOLATION

12.1 Introduction

The flow of fluids along the cement sheath is invariably an undesirable occurrence. For a producing
well, this is manifested either by the loss of reservoir fluids through crossflow along the cement
sheath, or by the influx of underground fluids from other formations into the active layer. For an
injector, the injected fluids may escape into unintended layers through the cement sheath. During
hydraulic fracturing, escape of fluids through an imperfect cement sheath may result in either
undesirable fracture-height migration or screenout of the intended fracture in the targeted formation
because of the fracturing fluid loss.

Almost all oil or gas reservoirs produce water. In mature or old fields which are typical for OMV
Petrom, the most of produced fluid is water, with oil or gas representing a few percent of total
production. A continuous increase in water production is thus a normal behavior in the lifetime of a
field.

Water flow paths in the reservoir, especially close to the wellbore, are often irregular, by-passing
large hydrocarbon saturated zones and inducing undesirable high water-cut levels. In such situations,
we are dealing with "bad" undesirable water, as opposed to "good" water produced under normal
conditions.

Undesired water production is one of the major technical, environmental, and economical problems
associated with oil and gas production. This water production can limit the productive life of the oil
and gas wells and can cause severe problems including corrosion of tubular, fines migration, and
hydrostatic loading. Also, upward gas flow or “gas migration” through and along the cement sheath
has received particular attention and often presents a problem that should be treated

Water shut off/zonal isolation (plugging of high water cut zone and perforating new intervals)
represents around 30-50% of the all workover operations in OMV Petrom to recomplete well and
provide continuation of production with lower water and gas cut.

Gas shut off is rarely performed and estimated frequency, based on collected statistical data, is
around 5%.

There is probably nothing more critical to the completion of a well, or in fact, stimulation of a well
than having good zonal isolation. Shortchanging in the quality of the cement and the cement/casing or
cement/formation bonds on primary cementing can cost huge sums of money in later stages of the
well, and could not be justified.

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12. ZONAL ISOLATION

12.2 Reasons and Objectives for Zonal Isolation

Isolate formation intervals

• Temporarily abandon production zone to test other intervals.
• Permanently abandon nonproductive zones.
• Resolve problem of unwanted water and gas production.
• Seal off lost-circulation zones opened during cementing or completion.
• Seal off depleted zones from production intervals in multizone completions (Figure 12-1).
• Stop lost circulation in open hole during drilling.

Figure 12-1 Depleted zone abandonment

Alter formation characteristics

Reduce the producing gas/oil ratio (GOR) by isolating the gas zones from adjacent oil intervals:
• Gas coning (Figure 12-2a): When the flowing pressure gradients become large enough to
overcome the gravitational forces, gas will form an unstable cone, which advances into
the wellbore. Coning tendencies are inversely proportional to density difference and
directly proportional to viscosity. The density difference between gas and oil is normally
larger than the density difference between water and oil.
• Gas Fingering: Preferential flow of gas through high permeability layers.
In stratified reservoirs, premature fingering of gas may occur with high pressure
drawdown at the wellbore, casing leaks, cement bond failure, natural or induced
fractures communicating with gas zone, or acidizing into gas zone. Fingering is more
prevalent in reservoirs where permeability varies appreciably between zones (Figure 12-
2b).
• Moving of the G/O contact in solution gas reservoir due to reservoir depletion (Figure 12-
2c).

Figure 12-2 a) Gas Coning; b) Gas Fingering; c) Moving G/O contact

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Reduce water-oil ratio.

• Oil/water contact moving up
Typically, this is associated with limited vertical permeability, usually less than 1 mD.
This problem can be considered as a subset of coning, but the coning tendency is so low that
near-wellbore shut-off can be effective (Figure 12-3).
• Water Coning (Figure 12-4a)
Water coning problem in vertical wells is defined as vertical movement of water across
bedding planes in a producing formation.
• High-permeability layer With/ Without crossflow (Figure 12-4b)
With crossflow: Water crossflow can occur in high –permeability layers that are not isolated
by impermeable barriers.
There is no barrier to stop crossflow in the reservoir and that is difference in comparison with
the water-out without crossflow.
Without crossflow: A common problem with multilayer production occurs when high –
permeability zone with a flow barrier (such as a shale bed) above and below is watered out
(“FINGERING”). The water source may be from an active aquifer or a waterflood injection
well.

Figure 12-3 Moving oil/water contact

Figure 12-4 a) Water coning; b) Water fingering

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12.3 Zonal Isolation Workflow

Figure 12-5 Zonal isolation Workflow

Zonal isolation methods:

 Squeeze cementing,
 Plug cementing,
 Selective cementing,
 Mechanically isolating by bridge plug,
 Mechanically isolating by retrievable packer,
 Mechanically isolating by cement plug,
 Mechanically isolating by sand plug, and
 Chemically isolating.

Mechanical tolls for zonal isolation are covered in Chapter 5 (Well Recompletion).

12.4 Remedial Cementing Technology

Before any remedial application, the existing downhole conditions, the cause and magnitude of the
problem, and the expected results from the application must be determined. Then the necessary
planning, design, and placement procedures can be engineered to match downhole conditions and
enable the operation to be completed. Whenever downhole problems, wellbore conditions, and
expected results cannot be defined or controlled, time and money will be wasted and the repair will
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probably be unsuccessful. In addition, more well damage or total well loss may occur if the wrong
decisions are made.

Remedial cementing operations consist of two broad categories: plug cementing and squeeze
cementing.

Cement plug

The process of setting a cement plug involves the placement of a relatively small amount of cement
slurry an open or inside casing. Cement plug is a volume of cement designed to fill a length casing or
openhole and to seal vertical fluid movement.

Cement plugs are usually placed to:

• Abandon lower depleted zones on cased hole.

• Plug and abandon an entire well.
• Provide a kick off point sidetrack drilling operation.
• To provide a seal for open hole testing.
• To cure a lost circulation zone .

There are three common techniques for placing cement plugs:

• Balanced-plug method,
• Dump-bailer method, and
• Two-plugmethod.

Squeeze cementing is defined as the process of forcing cement slurry, under pressure, through holes
or splits in the casing/wellbore annular space. When the slurry is forced against a permeable
formation, the solid particles filter out on the formation face as the aqueous phase (cement filtrate
enters the formation matrix). A properly designed squeeze job causes the resulting cement filter cake
to fill the opening(s) between the formation and the casing. Upon curing, the cake forms a nearly
impenetrable solid. In cases where the slurry is placed into a fractured interval, the cement solids
might cause a filter cake on the fracture face and/or bridge the fracture.

Normally, the slurry injection is performed through casing perforations. There are two different
squeezes can be performed:

 Low-pressure squeeze: The bottomhole treating pressure is maintained below the formation
fracturing pressure.
 High-pressure squeeze: The bottomhole treating pressure exceeds the formation fracturing
pressure.

Within these two classes, there are two basic techniques (the Bradenhead (no tool) squeeze and the
squeeze tool technique) and tree pumping methods (the running squeeze, staged squeeze and the
hesitation squeeze). Each of these classifications and techniques is explained in the sections below.

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REMEDIAL
CEMENTIN
G

SqueezeCementing PlugCementing

Low-pressure High-pressure
squeeze squeeze PlacementTechniques
P < Pfrac P > Pfrac

Balancedplug DumpBailer Two-plug

No Tool SqueezeTool
Placement Techniques PlacementTechniques

Retrievable Drillable
Bradenhead Bullhead Squeeze Cement
Packer Retainer

PumpingMethods

Continuous Staged Hesitated

Figure 12-6 WF Remedial cementing classification

12.4.1 Squeeze Cementing under Pressure below Formation Fracturing Pressure

Low-Pressure Squeeze

The aim of this operation is to fill the perforation cavities and interconnected voids with dehydrated
cement. The volume of cement is usually small, because no slurry is actually pumped into the
formation. Precise control of hydrostatic pressure of the cement column is essential, because
excessive pressure could result in formation breakdown.

With the development of controlled fluid loss cements and retrievable packers, the low-pressure
method has become the most efficient technique of squeeze cementing (Figure 12-7).

Low pressure, where the formation- is not broken down, is illustrated by the following equation:

𝑃𝑠 + 𝑃ℎ < 𝑃𝑓𝑟𝑎𝑐 (12-1)

Where:
Ps - Surface pressure, psi
Ph - Hydrostatic pressure of all fluids, psi
Pfrac (BHTP) - Fracture pressure (Bottomhole treating pressure), psi.

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Figure 12-7 Low pressure squeezing

With this technique, formation breakdown is avoided and pressure achieved by shutting down or
hesitating during the squeeze process. In this hesitation method, the cement is placed in a single
stage, but in alternate pumping and waiting periods. The controlled fluid loss properties of the slurry
cause filter cake to collect against the formation or inside the perforations while the parent slurry
remains in a fluid state inside the casing.

In low-pressure squeezes, it is essential that perforations and channels are clear of mud or other
solids. If the well has been producing, such openings may already be free of obstructions; however,
for newly completed wells, it may be necessary to clean the perforations before performing the
squeeze job.

Properly designed slurry will leave only a small node of cement filter cake inside the casing.
Improperly designed systems can result in excessive development of cement filter cake. This can
result in a complete bridging of the inside of the casing, with loss of pressure transmission to the
formation, and insufficient contact of the cement filter cake with the formation.

A low-pressure squeeze should be run whenever possible since this technique gives has the highest
success rate. The low-pressure squeeze requires only a small amount of cement slurry, while the high-
pressure technique usually involves a larger volume of slurry.

Squeezing low-pressure fractured zones

Low-pressure fractured zones are often difficult to squeeze because conditions are nearly always
considerably above the BHTR. This is shown by the equation:

𝑃𝑓𝑟𝑎𝑐 ≪ 𝑃𝑠 + 𝑃 ℎ − 𝑃𝑓 (12-2)

Where:
Pfrac-fracture pressure, bar (psi)
Ps - Surface pressure, bar (psi)
Ph - Hydrostatic pressure of all fluids, bar (psi)
Pf - Friction pressure, bar (psi).

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Usually, more than one stage of cement is required. It is extremely important to squeeze with the
least possible standing pressure.

In order to control the process properly, a packer should be used and the best is to load backside with
clear fluid and maintain about 70 bar (1000 psi). Pump into the formation to establish an injection
pressure. As soon as all the cement slurry is properly mixed, open the valve to the displacement tank
and let the displacement flow by gravity into the tubing until flow almost stops. Then start pumping
very slowly.

Perhaps a better approach than over displacing cement would be to allow the slurry to gravitate down
the tubing until some amount of displacement fluid is in the tubing behind the slurry. The surface
valve between the pump and tubing could be closed, slowing the fall of slurry. The valve could be
opened to allow more displacement fluid. Once cement is over displaced, the only thing that is certain
is that another squeeze will have to be performed.

Return in four to six hours for another stage. A hesitation type squeeze (i.e., an alternate hesitation
and pumping where the hesitation is to encourage cement filter-cake buildup) will probably be
required to attain squeeze pressure. The first hesitation probably will not decrease the bleed-off rate.
At this point in the squeeze, it becomes an art rather than a science. Continue to alternately pump and
hesitate until pressure bleed-off rate decreases and until a standing pressure is finally attained. The
amount of slurry to pump and the hesitation time is a matter of judgment. Hold a standing pressure
for about five minutes (varies with conditions) then flow back. Pressure-up to the original standing
pressure and hold for another five minutes. Flow back, then unseat the packer and reverse out the
excess cement. Be careful not to exceed the squeeze pressure when reversing.

Zones taking fluid on a vacuum are probably naturally fractured or have extremely high permeability.
Fractures may rake cement indefinitely with hesitations during the squeeze process, causing nominal
pressure buildups, while extremely high permeability may require very few hesitations before a
cement filter cake has been formed.

Figure 12-8 Squeezing fractured zones

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High-Pressure Squeeze

In some cases, a low-pressure squeeze of the perforations will not accomplish the objective of the job.
The channels behind the casing might not be directly connected to the perforations. Small cracks or
micro-annuli that may allow flow of gas do not allow the passage of cement slurry. In such cases,
these channels must be enlarged to accept a viscous solids-carrying fluid. In addition, many low
pressure operations cannot be performed if it is impossible to remove plugging fluids, or debris, from
ahead of the cement slurry or inside the perforations.
Placement of the cement slurry behind the casing is accomplished by breaking down the formation at
or close to the perforations (Figure 12-9). Fluids ahead of the slurry are displaced in the fractures,
allowing the slurry to fill the desired spaces. Further application of pressure dehydrates the slurry
against the formation walls, leaving all channels (from fractures to perforations) filled with cement
cake.

Figure 12-9 Probable result of high-pressure cement squeeze job

However, during a high-pressure squeeze, the location and orientation of the created fracture cannot
be controlled. Sedimentary rocks usually have an inherently low tensile strength, and are held
together primarily by the weight or the compressive forces of overlying formations.
These cohesive forces act in all directions to hold the rock together, but do not have the same
magnitude in all directions. When sufficient hydraulic pressure is applied against a formation, the rock
fractures along the plane are perpendicular to the direction of the least principal stress. A horizontal
fracture is created if the fracturing pressure is greater than the overburden pressure, while a vertical
fracture occurs if overburden pressure is greater than the formation fracture pressure. The extent of
the induced fracture is a function of the pump rate applied after the fracture is initiated. The amount
of slurry used depends on the way the operation is performed. High pump rates generate large
fractures; thus, large volumes of cement are required to fill them. A properly performed, high-
pressure squeeze should leave the cement as close to the wellbore as possible.
Drilling muds or other fluids with low fluid-loss rates should not be pumped ahead of the slurries. A
wash with a high fluid-loss rate, such as water or a weak hydrochloric acid solution, not only opens
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smaller fractures but also cleans perforations and the cement path. The fracture initiation pressure is
lower using this type of spearhead than using non-penetrating fluids.

2. Factors Impacting on Selection of Placement Techniques for Remedial Cementing

Regardless of the technique used during a squeeze job, the cement slurry is subject to a differential
pressure against a filter of permeable rock.
The resulting physical phenomena are filtration, filter cake deposition and, in some cases, fracturing of
the formation. The slurry, subject to a differential pressure, loses part of its water to the porous
medium, and a cake of partially dehydrated and cement is formed.
The cement cake, forming against a permeable formation, has a high initial permeability (Figure 12-
10). As the particles of cement accumulate the cake thickness and hydraulic, resistance increase; as a
result, the filtration rate decreases, and the pressure required dehydrating the cement’s slurry further
increases. The rate of filter-cake buildup is a function of four parameters:
 permeability of the formation,
 differential pressure applied,
 time, and
 capacity of the slurry to lose fluid at downhole conditions.

Figure 12-10 Cake permeability and dehydration rate of slurry

3. Best Practices for Design Cement Slurry

Lab tests are run prior to pumping cement in a well. Collecting accurate data prior to designing the
cement ensures a good cement design. The following factors will affect the cement slurry design:
 Well depth,
 Well temperature,
 Viscosity and water content of cement slurry,
 Strength of cement require to support the pipe,
 Quality of available mixing water,
 Type of workover fluid and density,
 Slurry density,
 Cement shrinkage,
 Permeability of set cement,
 Fluid loss requirements, and
 Resistance to corrosive fluids.
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12.5 Remedial Cementing Placement Techniques

The type of plug to be placed dictates the plug length, cement composition performance parameters,
and placement technique. The plug length mainly varies with placement techniques. The balanced-
plug method, requires the most volume since the method is the most prone to cement
contamination. The dump bailer method, usually used for temporary zonal isolation, requires short
lengths since cement is accurately placed over a solid base created by the bridge plug.

12.5.1 Cementing Plugs

Balanced-plug method

The balanced plug method is one of most frequently used methods (Figure 12-11). It is a simple
method and requires typical cementing service equipment. This method begins by placing a desired
quantity of slurry into the workstring and displacing it near the bottom of the workstring. The slurry is
often batch mixed for better density and rheology control. In addition, an appropriate volume of
spacer or chemical wash is pumped ahead of and behind the cement slurry to avoid any detrimental
contamination of the cement by the well fluid.

The volumes of spacer or wash are such that their heights in the annulus and work string/ tubing are
the same. When the height of cement inside the workstring is calculated to be equal to the height of
the cement that has exited the work string and traveled up the annular space, displacement is
stopped. Thus, when spacer fluid density is taken into consideration, the fluid inside and outside the
work string is calculated to be at a balance point. Once the cement is placed, the work string is slowly
pulled from the plug (27 to 43 m/min, 90 to 140 ft/min) to minimize disturbance of the cement. The
work string is retrieved to a point 10 to 15 stands above the calculated top of the cement, and reverse
circulation is started to displace any cement clinging to the pipe. It is common practice to slightly
under displace the plug (usually by 300 to 500 liters) to avoid well fluid flowback on the rig floor when
breaking the pipe connection after placement. This also allows the cement plug to reach hydrostatic
balance. Once the plug is balanced, the pipe is slowly pulled out of the cement to a depth above the
plug, and excess cement is reversed out, a shown in Figure 12-11.

Figure 12-11 Cement plug placed by balanced-plug placement method

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Setting a proficient plug is difficult because the cement slurry is usually much denser than the well
fluids. This density difference produces a gravitational instability that, in turn, allows the cement to
migrate downward through the well fluid(s) where the cement becomes contaminated.

Measures that can reduce the severity of cement contamination include:

• Improvements in hole-cleaning and/or slurry design.

• An increase in slurry volume.

The cement should be of such kind to gel quickly, and sufficient volume should be pumped to
minimize contamination.

Dump-bailer method

A dump bailer is a cylindrical container that holds a measured quantity of cement slurry and is run into
the well on wireline. A mechanically or electrically triggered mechanism on the bottom of the device
can open the bailer, releasing its contents into the wellbore at any specified depth. This method
(Figure 12-12) usually requires a mechanical packer, which is placed at the point of the plug bottom to
minimize migration of the small volumes of cement The method is limited by the volume of cement
that can be placed and by the depth at which placement can occur. However, the dump bailer
method has the advantage of accurate placement of small quantities of cement (an interval length in
the range 3 to 20 m ).

Placing plugs with dump bailers has generally not been very successful because of contamination with
borehole fluids and inability to dump viscous/ gelled slurry (standard neat cement) from the bailer.
There does not seem to be any significant difference in plugging success between gravity and positive
displacement type bailers. Dilution and contamination by wellbore fluids causes most of the small
slurry volume from each bailer run to be ineffective. Short plugs can sometimes be effective, but long
ones requiring multiple bailer runs usually are not.

However, unless coiled tubing is used, through-tubing plugging must be done with a bailer, requiring
multiple runs. These slurries must be mixed at the proper density and be designed with certain
properties.

Since placing a long plug in the hole so that it will be competent and stay in place cannot normally be
done with a dump bailer, it should be done through a workstring by either the balanced or two-plug
method.

The dump-bailer method involves setting a cement basket, permanent bridge plug or sand pack below
the desired plug location. The bailer then dumps the cement above the basket, bridge plug or sand
pack. The dump-bailer method is generally used at shallower depths. Present day retarders, however,
have increased the depth range to over 3500 m. These special slurry systems are engineered to
assure "dumpability" after long descents in severe well conditions. Dump-bailer cement slurries are
also engineered to provide maximum hydraulic seal with excellent anchoring.

Since the bailer is run on a wireline, the advantages of this method are low cost and depth control.
The disadvantages are adapting the method for setting deep plugs, contaminating the cement and the
slowness of the method.

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Figure 12-12 Cement plug placed by Dump Bailer

Two-plug method

The two-plug method involves running a top and a bottom wiper plug during placement of the
cement slurry (Figure 12-13). The bottom plug precedes the cement and wipes the inside of the
workstring, preventing contamination. The wiper plugs isolate the cement from wellbore fluids in the
work string.

When the bottom plug reaches the end of the workstring, it exits into the wellbore and the cement
moves up the annulus.

A special tool, called a plug catcher, can be run on the bottom of the workstring. The goal is to place
the plug catcher at the depth where the cement plug is desired. As the last of the cement exits the
plug catcher, the top plug seats in the plug catcher, resulting in a pump pressure increase, which
indicates that cement placement, is complete.

The design of the plug catcher allows the workstring to be pulled up after placing the cement. In that
way the cement is placed at the desired depth. Applying more pressure into the work-string will pump
the top plug down into a setting cage inside of the plug catcher. This then allows circulation through
the workstring.

To minimize contamination, centralizers and rotating scratchers can be put at the lower end of the
bottom work string or tail pipe. The rotation of the scratchers cleans bypassed working fluid or mud
and allows it to mix uniformly with the cement, thus eliminating fluid channels in the unset cement.

The two-plug method offers five main advantages:

• Minimizes the possibility of over displacing,

• Reduces mud and cement contamination,
• Produces a tighter, harder cement structure,
• Establishes the plug top more accurately,
• Costs less than other methods that may require several attempts to get a good plug.

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Figure 12-13 Two plug method

12.5.2 Technology Workflow for Cement Plug Placement

The workflow for placement cement plug/bridge is shown in Figure 12-14 .

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PROCEDURE / WORKFLOW FOR PLACEMENT

CEMENT PLUG OR BRIDGE

No Yes
RIH Tubing with Seating Nipple to
RIH Tubing with Seating Nipple to Cement Bridge? the dept of minimum 10m above the
top of open interval
the bottom of the open interval

Set up the Plug in Seating Nipple

with Wireline tool

Test Tubing mechanical sealing

integrity with Pressure
Pi= 0.05Ht
(Ht- tubing depth)
Yes No
Pressure drop after
No 15min
Tubing Test is OK

Yes Close preventer and rise pressure

in the well by Pi=0.05Ht
With WL Tool, Pull out the Plug
from Seating Nipple

Replace damaged part of Tubing

String Test Is OK, Well is sealed, WO can
be continued

Pump the Water, Cement slurry No

and Working fluid through the
Yes Fluid Inflow is
tubing
detected after 2
hours
No
Washout Cement slurry
by reverse circulation
Displace fluid from the well by
swabbing so Ph=0.5Ph
Yes POOH Tubing string, Scraper and
Bit
Very slowly rice up the tubing so Yes
the bottom of the tubing string be
at the depth of the top of cement No
plug Test mechanical sealing
Drill Cement Plug/Bridge and integrity by swabbing the well
Wash out the Well by Reverse
Circulation
By Reverse circulating with
working fluid wash out the
excess volume of Cement slurry.
Test cement bridge mechanical
The volume of the working fluid
RIH Tubing string, Scraper and sealing integrity
is V=1.5Vt(M3)
Bit
Yes

POOH 10 Pieces of Tubing

No
Good quality of cement plug/
POOH the Tubing string
bridge is placed on target/
designed depth
Allowing the cement enough time
to develop its bonding and
sealing properties

RIH Tubing, Check the Depth and Consistency

of the Cement Plug/Bridge – Procedure for
checking plug/bridge quality

Figure 12-14 Cement plug placement workflow

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12.5.3 Squeeze Cementing PlacementTechniques

Bradenhead Placement Technique

This technique, illustrated in (Figure 12-15), is normally used when low-pressure squeezing is
practiced, and when there are no doubts concerning the capacity of casing to withstand the squeeze
pressure. No special tools are involved, although a bridge plug may be required to isolate other open
perforations further downhole.

Open-ended tubing is run to the bottom of the zone to be cemented. Blowout preventer (BOP) rams
are closed over the tubing, and the injection test is performed. The cement slurry is subsequently
spotted in front of the perforations.

Once the cement is in place, the tubing is pulled out to a point above the cement top, the BOPs are
closed, and pressure is applied through the tubing. The Bradenhead squeeze is very popular because
of its simplicity.

The bradenhead squeeze technique is most aptly applied when repairing split or corroded casing. The
technique involves placing a cement plug below, across and above the interval to be squeezed. Then
the workstring is extracted to some distance (60-120m) above the cement plug. After reverse
circulating to assure that no cement is around the workstring, pressure is applied to the cement
column for dehydration until the cement is set and achieves approximately 100 psi compressive
strength. The maximum surface pressure to be put on the cement column should not exceed bottom
hole fracturing pressure less the hydrostatic pressure. The pressure may then be bled off while the
cement attains desired compressive strength prior to drilling out.

Bradenhead squeeze technique is very often applied when squeezing off perforations and abandoning
a depleted zone.

Figure 12-15 Braden head placement technique

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Bullhead method
This technique can be used with or without downhole tools on the tubing. The wellhead annulus is
closed at the beginning and cement is pumped down the tubing by displacing into the formation
whatever fluid happens to be in the well.
When downhole problems prevent the hole from being circulated and cleaned, or the problem
cannot be addressed by conventional perforating and squeezing, the cement may have to be
bullheaded down the annulus. Although bullheading is not a true squeeze technique, it may be the
only way to seal off a troublesome zone. Bullheading pushes everything ahead of the cement into the
formation; therefore, care must be taken to ensure that incompatible fluids are not forced into
potential producing formations. Often, low-density, high-yield, inexpensive slurries are used, because
large slurry volumes and multiple attempts may be necessary to complete this process.
The detailed workflow of squeeze cementing without using squeeze tolls by pumping the cement
slurry direct through tubing is shown in Figure 12-16.
Squeeze Tool Placement Technique
This technique can be subdivided into two parts: the retrievable squeeze packer method, and the
drillable cement retainer method. The main objective of using squeeze tools is to isolate the casing
and wellhead while high pressure is applied downhole.
Tool selection and placement are critical since using the wrong tool may cause more problems to
occur after the squeeze. Two basic types of tools are used for squeeze cementing: retrievable and no-
retrievable (drillable). A wireline or mechanical bridge plug seals off the zone below the squeeze
interval to keep the slurry from being pumped, or from freefalling down the casing. Most plugs are
drilled after the job; however, some can be retrieved if they are not cemented in place. Sand is often
placed on top of the plug to prevent it from being cemented and to allow retrieval after the job. This
technique is especially useful for squeezing multiple zones. When they plan to reverse-circulate
excess cement after placement, operators use a retrievable packer above the zone. Retrievable
packers are equipped with bypass valves that permit complete circulation of the wellbore (1) while
the tool string is being run in the hole, (2) after the packer has been set, or (3) during reverse
circulating after the job. This circulation capability prevents excessive pressure from being applied to
the formation while the tool string is being run into in the hole, and it prevents the well from being
swabbed when the packer is released and retrieved. Retrievable packers can be either tension- or
compression-set and can be run on wireline or a workstring. Drillable packers or retainers can also be
used; however, double check-valves are built into these tools to prevent unwanted flow from either
direction. Once the packer is set, a workstring is strung into the retainer, and then cement is pumped
and squeezed below the retainer. The workstring is then pulled out, and the retainer is closed.
Retainers are often used to help prevent pressure reductions in the wellbore from causing cement
flowback either after the squeeze job or when the cement is separating zones that have a high
pressure differential. Setting a retainer between the zones isolates the intervals and permits to
squeeze the lower zone and the upper zones in one application.
Retrievable Squeeze Packer Method
Retrievable packers with different design features are available (Chapter 5, WELL RECOMPLETION).
Compression- or tension-set packers are used in squeeze cementing. As shown (Figure 12-17), they
have a bypass valve to allow the circulation of fluids while running in the hole, and once the packer is
set. This feature allows the cleaning of the tools after the cement job, and the reversing out of excess

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slurry without excessive pressure; it also prevents a piston or swabbing effect while running in or out
of the hole.

Procedure of Squeeze Cementing Through

Tubing with Pressure Lower than Fracturing
Pressure Squeeze cement slurry in open
Interval with pressure lower than
fracturing pressure
RIH Tubing with seating nipple
to the bottom of the interval witch
should be closed
Leave the well under final treatment
pressure for period 4-6 hours
Set up plug in seating nipple with
wireline tool
Bleed of pressure, open preventer
and POOH tubing string
Test tubing mechanical sealing integrity
with maximum pressure witch is expect at
the wellhead during cementing job
RIH tubing string, scraper and
drilling bit
Yes
Tubing test OK
No After cement thickening (typically 4-6 hours-
at least minimum 30 min greater than time
required to place cement and reverse out
Replace damaged part of the tubing
excess cement slurry volume) check the depth
string
and consistency of the cement plug by
increasing the weight up to 5tons

With wireline tool pull out the plug from

D seath No
Is cement plug
consistent?

Connect cement displacement pump

and Well Yes

No
Is the depth of
Test mechanical integrity of surface cement OK?
injection lines with maximum pressure
witch is expect at the wellhead during Yes
cementing job
Test mechanical sealing integrity by
No swabbing the well Ph=0.5Pr
Surface injection
lines test OK
Yes Drill cement plug and repeat
cementing job

Set up cement plug No

Depth
of cement
Replace damaged part of the surface plug is shallower
injection lines than designed
dept

Yes

Yes Wash Drill cement plug to the designed

Pull up tubing to dept of out the excess depth
cement slurry flushing volume of cement
slurry
Test
No No
By reverse circulating with mechanical
working fluid, wash out sealing integrity
Pull up tubing above
the excess volume of is OK
the depth of cement
cement slurry. The volume Yes
slurry and water
of the working fluid is
column
V=1.5Vt(M3)
Perforate new interval and
POOH tubing string, complete the well for
scraper and drilling bit production
Close preventer and
casing valve

Figure 12-16 Squeezing cement through tubing with pressure lower than formation fracturing pressure

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The principal advantage of the retrievable packer over the drillable retainer is its ability to set and
release many times, thus allowing more flexibility. Retrievable bridge plugs can be run in one trip with
the packer, and retrieved after the slurry has been reversed or drilled out. Most operators drop one
or two sacks of frac sand on top of the retrievable bridge plug before the job, to prevent the settling
of cement over the releasing mechanism.

Another important advantage of using retrievable packers is that they are usually full-opening tools.
This allows for running wireline and other tools through and below the packer (i.e., perforating and
logging tools, wiper balls, etc.).

Figure 12-17 Bridge plug with cement packer

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Drillable Cement Retainer

Cement retainers are used instead of packers to prevent backflow when no cement dehydration is
expected, or when a high negative differential pressure may disturb the cement cake. In certain
situations, potential communication with upper perforations makes the use of a packer a risky
operation. When cementing multiple zones, the cement retainer isolates the lower perforations, and
subsequent zone squeezing can be performed without waiting for the slurry to set. Cement retainers
are drillable packers provided with a valve which is operated by a stinger at the end of the work string
and can be set either on wireline, tubing or coiled tubing (Figure 12-18).

A drillable retainer gives the operator more confidence in setting the packer closer to the
perforations. This is also advantageous in that a lower volume of fluid below the packer is displaced
through the perforations ahead of the cement slurry.

Drillable bridge plugs are normally used to isolate the casing below the zone to be treated. Their
design is similar to that of cement retainers. They can be run with a wireline or with the work string.
Bridge plugs do not allow flow through the tool.

Figure 12-18 Drillable cement retainer set and/or operated on wireline, tubing or coiled tubing

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12.5.4 PumpingTechniques

Running Squeeze Pumping Method

During a running squeeze procedure, the cement slurry is pumped continuously until the final desired
squeeze pressure (which may be above or below the fracture pressure) is attained. After pumping
stops, the pressure is monitored and, if the pressure falls due to additional filtration at the
cement/formation interface, more slurry is pumped to maintain the final surface squeeze pressure.

This continues until the well maintains the squeeze pressure for several minutes without additional
injection of cement slurry. The volume of slurry injected is usually ranging from 1.5 to 15 m3 (10 to
100 barrels).

Staging Technique

Staging is sometimes referred to as the batch method. When the pumping process fails to result in
reaching the desired squeeze pressure, it is usually over displaced (put away) and allowed to set up
(harden, or at least develop sufficient gel strength until it cannot be pumped). Then another
stage/batch of cement is used to try again. The process is repeated until the squeeze pressure is
obtained, which may or may not happen after many successive attempts.

Hesitation Squeeze Pumping Method

In this process, pumping is stopped occasionally for short periods of time during the pressure building
process to allow the cement slurry to dehydrate slightly and build a filter cake against the exposed
rock. As these voids are plugged, they allow pressure to be increased in the next pressurization
period, so that the liquid cement slurry that remains can be placed into new voids at the higher
pressure. This maximizes the opportunity to get slurry into all the voids, which in turn helps achieve
the desired squeeze pressure with the first batch of cement and eliminate the need for additional
stages. It is a useful technique in all wells, and is usually required for low permeability formations
where cement filter-cake buildup is very slow.

This procedure involves the intermittent application of pressure (at a rate of 1.5 to 3 m3/min, 1/4 to
1/2 bbl/min), separated by an interval of 10 to 20 minutes for pressure leak-off due to filtrate loss to
the formation. This allows time for the cement which has been placed into the perforations tunnel to
dehydrate against the formation. After the pressure has stabilized or after 10 minutes, pressure up on
the cement plug again. Continue to pump until the pump pressure begins to move the cement again
i.e. the pump pressure will stabilize. Pump 3 to 6 m3 bbl after the cement begins to move, and then
shut down the pump. It is required to wait until the pressure bleeds back and begins to stabilize or a
maximum of 10 minutes. Continue this staging process until the cement will no longer move (i.e. the
pump pressure reaches the fracturing pressure of the zone or the burst strength of the tubulars).

The initial leak-off is normally fast because there is no filter cake. As the cake builds up, and the
applied pressure increases, the filtration periods become longer and the difference between the initial
and final pressures become smaller, until at the end of the job the pressure leak-off becomes
negligible (Figure 12-19). The volumes of slurry necessary for this technique are usually much less
than those required for a running squeeze.

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Figure 12-19 A typical pressure chart of a hesitation squeeze

Building Final Squeeze Pressure

In reality, the conditions within the formation being squeezed will determine which is most likely to
occur. A properly executed injection test will reveal this. A loose injection profile indicates that
hesitation and pump cycles are probably needed to achieve a successful squeeze. A loose injection
profile can also be a candidate for a running squeeze in cases when injection is the consequence of
high permeability. Frequently it is difficult to distinguish between permeability and fractures from the
surface. A tight injection profile will indicate a running squeeze is likely. However, these trends are not
hard and fast rules.

A competent hesitation designed and tested slurry can easily obtain a running squeeze, if the
formation is conducive to a running squeeze and is not damaged in the process. Slurries without
sufficient fluid loss control and/or not tested on a hesitation schedule are not effective when
hesitating and may dehydrate prematurely. These type slurries are also not effective at obtaining a
running squeeze. They may dehydrate prematurely and block slurry from reaching the tighter areas
within the squeeze zone. Surface indications can show a high final pressure and what appears to be a
good squeeze. Often the pressure is exerted against a bridge of dehydrated cement, preventing the
transmission of pressure to the formation.

The hesitation test verifies that the slurry can be stopped and started again any number of times
while remaining fluid and pumpable. Even when it is certain that a running squeeze is going to occur,
the first thing to be done after reaching the maximum allowable pressure is to stop the pump. The
pressure is monitored to see if it is going to hold or leak off. If it holds, a running squeeze has occurred
and it is time to reverse out the excess cement in the workstring.

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Figure 12-20 Squeeze cementing through tubing, packer or cement retainer

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Figure 12-21 Squeeze cementing through tubing, packer or cement retainer (continuation)

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Figure 12-22 Squeeze cementing through tubing, packer or cement retainer (continuation)

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12.5.5 Squeeze Cementing Placement Techniques

Figure 12-23 Isolating of the production interval (one zone)

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Figure 12-24 Isolating of the production interval (two or more zones)

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6. Materials Used for Remedial Cementing

Cement

Portland cement is used during almost all well cementing jobs. It is a finely divided and highly reactive
powder. The vigorous hydration of Portland cement during initial mixing, as well as the changeable
slurry properties during placement, complicates the design of cement mixing and pumping
equipment.

Portland cement is usually stored in silos at a central storage location. Alternatively, it is packaged in
metric (50-kg) sacks, and in so-called “big bags” (1 to 1.5 metric tons generally), or in larger quantities
(truck, railway car, or ship).

Water

Fresh water is normally used for cementing onshore wells, and seawater for offshore locations.
However, one must be aware that fresh waters are often not very “fresh.” Inorganic salts and organic
plant residues are frequently present in significant quantities. Such materials are known to affect the
performance of Portland cement systems.

Additives

Additives modify the behavior of the cement system, ideally allowing successful slurry placement,
rapid compressive strength development and adequate zonal isolation during the lifetime of the well.

1. Cement Types (Standard and Special Types)

Portland cement

Portland cement is by far the most important binding material in terms of quantity produced; indeed,
it is possible that it may be the most ubiquitous manufactured material. Portland cement is used in
nearly all well cementing operations.

Portland cement is the most common example of Hydraulic cement. Such cements set and develop
compressive strength as a result of hydration, which involves chemical reactions between water and
the compounds present in the cement, not upon a drying-out process. The setting and hardening
occur not only if the cement/water mixture is left to stand in air, but also if it is placed in water. The
development of strength is predictable, uniform and relatively rapid. The set cement also has low
permeability, and is nearly insoluble in water; therefore, exposure to water does not destroy the
hardened material. Such attributes are essential for a cement to achieve and maintain zonal isolation.

API Classification System

 Class A: Intended for use from surface to a depth of 1830 m (6000 ft), when special properties
are not required.
 Class B: Intended for use from surface to a depth of 1830 m (6000 ft), when conditions
require moderate to high sulfate resistance. Has a lower C3A content than a class A.

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 Class C: Intended for use from surface to a depth of 1830 m (6000 ft), when conditions
require high early strength. Class C is available in all three degrees of sulfate resistance. To
achieve high early strength, the C3S content and the surface area are relatively high.

Classes D, E and F are also known as“retarded cements,” intended for use in deeper wells. The
retardation is accomplished by significantly reducing the amount of faster-hydrating phases (C3S and
C3A), and increasing the particle size of the cement grains.

 Class D: Intended for use at depths from 5,000 ft (1,520 m) to 10,000 ft (3,050 m), under
conditions of moderately high temperatures and pressures.
 Class E: Intended for use from 6000 ft (1830 m) to 14,000 ft (4,260 m) depth, under
conditions of high temperatures and pressures.
 Class F: Intended for use from 10,000 ft (3,050 m) to 16,000 ft (4,870 m) depth, under
conditions of extremely high temperatures and pressures.

Classes G and H were developed in response to the improved technology in slurry acceleration and
retardation by chemical means. The manufacturer is prohibited from adding special chemicals, such as
glycols or acetates, to the clinker. Such chemicals improve the efficiency of grinding, but have been
shown to interfere with various cement additives.

 Class G: Intended for use as a basic well cement

 Class H: surface to 8,000 ft (2,440 m) depth 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 sulfate or water, or both, shall be blended with the clinker
during manufacture of Class G and H well cements.

The chemical compositions of Classes G and H are essentially identical. The principal difference is the
surface area. Class H is significantly coarser than Class G, as evidenced by their different water
requirements.

Table 12-1 Application of API Classes of Cement

Thixotropic Cement
Thixotropic cement is intended to control loss of whole cement into a fractured or highly permeable
zone, such that a seal around the wellbore can be obtained. It consists of a mixture of API Class G
cement modified with about 6 to 8% sulfate, which provides pumpable slurry as long as it is being
moved but which develops high gel strength rapidly when not agitated. In application, it is usually
spotted over the zone to be sealed off, and a shortened ‘’hesitation squeeze’’ technique used to

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obtain a pressure buildup. A more recent thixotropic type cementing formulation contains about
896.364 kg/m3 (1 Ib/sk) of gum cross linked with an organic material, dry-blended with API Class G
Cement. Also, thixotropic cement can be used to squeeze a low-pressure zone. This special slurry is
pumpable as long as tie slurry is moved, but its thixotropic (or high gel strength) properties provide a
rapid set and strength buildup when it is not agitated or moved. This property may initiate bridging
or plugging of fractures resulting in a rapid pressure buildup, especially during a hesitation squeeze.
Thixotropic cement may be used as lead slurry followed by high fluid loss slurry.
Two-Stage Sodium Silicate-Cement System
A second technique designed to plug a fractured or highly permeable zone involves a two-stage
treatment. The first stage is a sodium silicate-like polymer solution containing fibrous material and/or
sand for bridging. This mixture forms a stiff gel when it comes in contact with formation saltwater (or
injected saltwater). This, in effect, temporarily seals the formation permeability, such that the second
stage, consisting of normal squeeze cement slurry, is contained in the vicinity of the wellbore to
provide a permanent shut-off.
Silica Flour, or Silica Sand, is normally used at a concentration of 35% by weight of the cement when
the cement slurry will be exposed to flowing temperatures of 110°C (230°F), or greater. At 110 -
176.6°C (230-350°F), silica flour reacts faster than silica sand. Above 176.6°C (350°F), reaction rates
are practically the same, but silica sand is easier to mix.

Diesel Oil Cement (DOC)

The purpose of diesel oil cement is to control extraneous formation water. DOC consists of Portland
cement mixed in diesel oil or kerosene (no water) with a surfactant to improve wetting of cement
particles. The cement will not set up until it is contacted with water, hopefully from the extraneous
water zone. Successful application of DOC requires that it be properly placed in contact with the
water zone and that it not contact water from the producing zone. As a practical matter, this
requirement limits the usefulness of diesel oil cement systems.

Ultrafine Cement
Ultrafine cement or Micro Matrix (trade name) has an average particle size of about 4-5 microns,
compared with about 100 microns for normal Class A or G cement. In laboratory tests ultrafine
cement particles penetrate opening as small as 5 microns (0.002 in)—or clean sands as fine as 100
meshes. Thus, ultrafine slurries may have possibilities for squeeze cementing small-opening casing
leaks, small channels or fractures, and gravel packs. With greater particle surface area strength
buildup is more rapid than normal cement slurries under similar curing conditions.
It should be recognized that in formations having larger pore openings or fractures, the cement
particles (not just the filtrate) may enter the pore channels to plug off some distance away from the
wellbore. With a normal cement particle size, the particles bridge off or form filter cake on the
formation face. All that enters the formation pore system is the cement filtrate which is usually
considered to be non-damaging. This may not be true with ultrafine cement slurries.

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2. Foamed Cement

Foamed cement is a fine dispersion of gas (usually nitrogen) in cement slurry, which contains a
foaming surfactant and foam stabilizer. Foam quality is the ratio between the volume occupied by the
gas and the total volume of the foam, expressed as a percentage. Foamed cements are dilute foam
where spherical bubbles are separated by viscous film and the quality is less than 50%.
Foam density is dependent on final slurry property requirement. Cement slurry with normal water
density ranges between 1761.45 - 1977.14 kg/m3 (14.7 to 16.5ppg) require high nitrogen volume
whereas extended slurries need less gas. Common foam densities applied in the field are from 838-
1437 kg/m3 (7 to 12 ppg) with compressive strengths of 35-83 bar (500 to 1200 psi, respectively.
Because of the thixotropic nature of the foamed cement, it resists in-flow from the formation. The
cost of these treatments compares favorably with those using perlite or microsphere cements. Major
savings are achieved resulting from reductions in rig time, because the need for the setting of lost-
circulation plugs is eliminated.

3. Cement Additives

Eight categories of additives are generally recognized:

1. Accelerators: chemicals which reduce the setting time of a cement system, and increase the
rate of compressive strength development.
Calcium Chloride is the most common accelerator used. Calcium Chloride does not increase
the final strength of cement and may perhaps lower the final compressive strength a little.
Most fluid loss additives do not work well with Calcium Chloride in the cement slurry. Sodium
Silicate is recommended if low fluid loss is required with fluid loss control in most cases.
Special mixing is required for sodium silicate slurries:
 if accelerator is used then the accelerator must be added first.
 if a retarder is to be used then the Sodium Silicate should be added first and
the retarder must be added last.
Accelerated slurries are also used as a restriction to help attain a squeeze. Slurries can be
accelerated to set in 15 minutes using control-setting gypsum cement. Two-phase slurry can
be used with accelerated lead slurry followed by high fluid loss slurry. The intent is to slow
down or restrict the accelerated slurry squeeze with the high fluid loss slurry. Fluid loss
characteristics may be adjusted on the tail-in slurry depending on the permeability of the
formation. Accelerated slurries increase the risk of premature setting, so use them cautiously.
2. Retarders: chemicals which extend the setting time of a cement system.
Lignosulfonates and their derivatives make up the majority of the cement retarders for use in
low and medium temperatures. (25°C– 105°C) Higher temperature retarders are composed
of Polyhydroxy Organic Acids and sugar derivatives.
3. Extenders: materials which lower the density of a cement system, and/or reduce the quantity
of cement per unit volume of set product (decreasing the total cost).
Pre-hydrated Bentonite is the best example of cost saving of neat cement slurry. However, if
low fluid loss is required, the cement can become more expensive as the increased water in
the system requires more chemicals to prevent it from escaping from the slurry. Sodium
Silicates have also been used to lower the density of cement but are more expensive than
pre-hydrated Bentonite.

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4. Weighting Agents: materials which increase the density of a cement system.

Hematite (a form of Iron Oxide) is normally used to densify cement, but manganese
tetraoxide is also available (Micromax). This product has a lower specific gravity than
Hematite but is spherical and small in size. It has two primary advantages:
 it is ground small (less than 1 micron) which allows it to be blended in the
mix water,
 it is spherical which makes the gel strengths much lower, thus reducing the
viscosity.
Weighting Materials should be used only if additional cement density is required to contain
abnormally high formation pressures. It is not recommended at all to use thin slurries when
using weighting materials due to excessive settling problems.
5. Dispersants (Friction Reducers): chemicals which reduce the viscosity of cement slurry.
The functions of dispersants are:
 to thin the slurry in order to reduce the turbulent flow rate or enable
easy mixing of slurry.
 to densify cement slurry (increase the solid-to-liquid ratio).
 to aid in fluid loss control.
Dispersants, and/or friction reducers, should be used only if the slurry must be thickened
without the use of weighting materials.
6. Fluid-Loss Control Agents: materials which control the loss of the aqueous phase of a cement
system to the formation.
This class of cement chemicals and gas migration additives are generally the most expensive
part of the cementing invoice. If high fluid loss occurs the following can happen:
 Premature dehydration of slurry, which can cause annulus plugging and incomplete
placement of slurry.
 Changes in slurry flow properties (rheology) and increased slurry density.
 Damage to production zones by cement filtrate.
7. Lost Circulation Materials (LCM): materials which control the loss of cement slurry to weak
or vugular formations.
8. Specialty Additives: miscellaneous additives, e.g., antifoam agents, fibers, bridging agents etc.
Anti-Foaming agents are used only if slurry aeration is expected to present a mixing problem,
or a downhole density problem. Anti-Foaming should be used when mixing salt cement
systems or using sea water as mixing water.
Bridging agents, such as Gilsonite (a natural, resinous hydrocarbon or natural asphalt),
perlites (naturally occurring as siliceous rock, that when heated to a suitable point in its
softening range, expands from four to twenty times its original volume) and sand has been
used with good success. Perhaps the best of these is Gilsonite. Many combinations have been
tried and they all may be acceptable for a particular situation. For instance, two-phase slurry
may be used. The lead blurry may have 5 lb of Gilsonite per sack, followed by neat cement.
The intent here is to bridge oil with the lead slurry and squeeze with its tailin slurry. Some
people take an entirely different approach. They run the neat slurry ahead of the bridging
agent. The intent is to be sure to get some cement into the formation before a squeeze
occurs. If this is the situation, then the design was proper.

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9. Non-Foamers
The function of non-foamer (defoamers) in cement slurry is to release trapped air in the slurry
as it is being mixed. Entrapped air causes viscosity increases, which make the cement
slurry more difficult to mix. Entrapped air also makes the density of the slurry more difficult
to measure. The addition of excess non-foamer can stabilize foam. Bentonite cement slurries
usually require twice much non-foamer than conventional cements. Latex cements may
require as much as five times more non-foamer than conventional cement slurries.

12.6.4 Spacers andWashes

There are two major concerns related to the success of cement placement. Cleaning of perforations
and surrounding voids. Solids-carrying fluids or drilling mud must be removed from the perforation
channels and the formation face to allow a proper dehydration process and complete fill-up.

Slurry properties, such as fluid loss, thickening time, and viscosity, can be modified by cement contact
with completion fluids. A small quantity of contaminated slurry, having a high fluid-loss rate or high
viscosity, may readily block channels and prevent optimum slurry placement.

In low-pressure squeezing, treatments related to the first point are performed as a separate stage.
Usually, cement slurry contamination is avoided by pumping a compatible water spacer ahead of and
behind the cement. If the cement is not spotted, a chemical wash or weak acid solution may be
squeezed ahead of the slurry, separated by a compatible fluid.

Cement properties for various squeeze and plugging applications are outlined in Table 12-2 and Table
12-3.

Table 12-2 Cement properties for various types of squeeze application

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Table 12-3 Cement properties for various types of plug application

5. Laboratory Procedure for Testing Cement, Slurry, Foamed Cement

Types of Tests
The cement lab routinely performs the following test on all field cement jobs:
 Thickening Time (pumping time),
 Fluid Loss (only if the slurry contains fluid loss additives),
 Free Fluid (free water, vertical or 45 degrees),
 Rheology (determine turbulent flow rate),
 Sonic Strength (compressive strength), and
 Slurry Density (pressurized density balance).
The cement lab can perform the following additional tests at the special request:
 Static Gel Strength,
 Settling (density settling),
 Expansion (both linear and radial),
 Cement-Spacer-Mud compatibility,
 Gas Migration Potential, and
 Cement ROP (Kick-off/Sidetrack Plugs).
Cement Samples should be sent for testing for the following reasons:
 Forman or Engineer suspects a problem with cement additives or mix water.
 Service company lab not functioning.
 BHST > 100°C.
 Abnormal well conditions that may adversely affect the cement job.
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12.7 Models for Planning and Designing Remedial Cementing Jobs in OMV
Petrom

Squeeze Job Planning

Planning is the most important single step in any squeeze operation. Well conditions should be
studied and objectives should be carefully established as squeeze cementing can be complicated and
expensive. Once the need for a squeeze cement job has been confirmed, planning, design, and
execution procedures can be combined into a successful program. The fourth and final step in any
squeeze-cementing operation is a proper evaluation of the successful application. The guidelines
presented in Table 12-4 can be used to complete these processes.

Table 12-4 Remedial cementing planning, designing and executing processes

Process of Designing a Cement Squeeze Treatment

Process What to do Notes
Planning  Determine the problem and reason The most important basic rule in job
to squeeze and/or plug. planning is to determine the problem.
 Analyze the wellbore conditions. This is absolutely essential. If some sort
 Select the appropriate squeeze and of understanding about the problem
plug placement technique. cannot be reached, a diagnostic
procedure should be initiated.

Designing  Select the proper tools for squeeze Many factors affect squeeze
and plug. applications; however, when the
 Select all other fluids used in the problem is diagnosed properly and a
process, i.e., perforating. good plan is prepared, a squeeze and
 Fluids, acids, cement spacers, plug cement design can be a fairly simple
completion fluids, etc. process.
 Design the cement slurry to correct The design of the job starts with the
the problem. definition of the objective. Setting a plug
 Prepare a detailed job procedure. for lost circulation is quite different from
setting a plug to abandon a depleted
zone or to plug back a well.
Executing  Prepare the wellbore and clean all Once the plan has been established and
voids to be squeezed. the calculations have been double
 Set the squeeze tools at the desired checked, the last phase of the squeeze
locations. program is the implementation of
 Set equipment and mix the slurry squeeze and plug workflows and
properly. procedures.
 Place the cement and apply the The detailed workflows and detailed
squeeze pressure. procedures for squeeze cement or using
 Hold the cement in place until it cement plugs should be applied.
hardens.
 Allow enough WOC time to test or
log the squeeze job.
Evaluating  Perform positive and negative The primary quality control and job
pressure test. evaluation for a of remedial cementing
 Perform bond log. operation is the application of hydraulic
 Acousticlog. pressure to the treated interval. A
 Temperature profile. cement bond-log (CBL) or evaluation
 Radioactive tracers. tool (Cement-Sheath Evaluation) can
measure annular cement fill,
compressive strength, and the bond
integrity of the cement.

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1. Chemical Methods for Water Control

Alternative approach to Workover is to squeeze (bullheading) all zones with one of the available
Organic Crosslinked Polymer (OCP) - Sealants or Relative Permeability Modificator (RPM).

Polymer gels often represent a valid and economic alternative to mechanical isolation, but, their
application requires the water zones to be identified and isolated. Therefore, in micro-layered
formations, excessive water rates can determine a premature abandonment when no efficient and
low-risk water control technologies are identified.

Water Shutoff by Relative Permeability Modifier (RPM) Polymer Treatments

An option, that can be considered when conventional approaches cannot be applied, is the injection,
into all open intervals, of chemicals that selectively reduce the permeability to water (RPM
bullheading treatments).

The systems that are most commonly used for this purpose are solutions of water-soluble, high
molecular weight polymers that adsorb onto the pore surface and change the flow properties of the
porous medium. The main advantages of this approach are:

 Low cost (the chemical is used in limited quantities and the treatment does not require zone
isolation).
 Low risk (the polymer reduces the water permeability without plugging the formation).
 Low environmental impact.

Although the application of these treatments in the field is relatively simple, field tests generally can
be carried out in the absence of reliable criteria to select candidate wells and chemicals. This trial-
and-error approach is responsible for the moderate success ratio and for the difficulties in interpreting
filed-test results.

Starting from the main operative questions key mechanisms that operate at the different scales in
the reservoir should be defined and analyzed.

Well Candidate and Chemical Selection

From the operator’s point of view one of the most important needs in the field application of RPM
treatments is to be able to formulate reliable answers to the following key questions:

 Will selected well respond to an RPM treatment?

 What chemical system and operating conditions (volumes, flow rates, etc.) will give optimal
results?
This implies the availability of rules to be applied in each particular case on the basis of field data. The
development of such reliable criteria requires systematic study of the key physical and chemical
mechanisms that operate in the different phases of a treatment (selection of the chemical, injection,
post-treatment).
The best candidates are wells in multi-layered matrix formations with one or more layers that are still
saturated with hydrocarbons. If water is mobile in all productive layers the benefits from an RPM
treatment can be of limited duration because it may cause significant reductions in bottomhole
pressure.
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Water Shut-off by Organically Crosslinked Polymer (OCP) Treatments

The OCP system is based on a copolymer of acrilamide and t-butyl acrylate (PAtBA) crosslinked with
polyetylenamine (PEI). It is applied as solutions for water coning, / cresting, high-permeability streaks,
fracture shut-off and or casing-leak repair. The OCP system has been successfully applied to
sandstone, carbonate, and shale formation in need of conformance treatment.
This method is applied in the cases where water and hydrocarbon zones are clearly separated.
The principle of operation of this technique is to pump the polymer system into the formation around
the wellbore and allow it to propagate through the rock matrix. In-situ gelation takes place, plugging
pore spaces and channels, thus, limiting undesired water flow.
This system has a temperature range from 21 to 177oC. The sealant system components are easily
diluted in the mixing brine. The cross-linking process is activated by the temperature of the well. The
crosslinking rate is dependent on temperature, salinity, pH, and base polymer and crosslinker
concentrations. The sealant system offers the following advantages:
It is low-viscosity fluid system (20-30 cP) that can be easily injected deep into matrix of the formation
without underground hydrolysis and precipitation. It is well-known that chrome-based system tends
to hydrolyze and precipitate, especially with increasing pH and temperature. It provides adequate
pumping times in environments up to 177 °C to obtain adequate placement time before the system
undergoes the phase change from liquid to a three-dimensional gel structure. This transition time is
completely controllable and predictable with the crosslinker concentration for a given temperature.
It provides effective permeability reduction and sufficient strength for resisting drawdown pressure
inside the wellbore and stopping water. The system provides sufficient strength for resisting
differential pressure of at least 172 bar (2500 psi). Thermal stability of OCP has been tested up to
191oC and it is not sensitive to formation fluids, lithology, and/or heavy metals.
This kind of polymer tends to selectively enter and seal off the more permeable zones, which are
probably producing the highest volume of water.

12.8 Downhole Equipment for Remedial Cementing

Remedial cementing tools are mechanical and/or hydraulic devices that are used down-hole to assist
in cement slurry placement, isolation, fluid control and pressure control during the remedial
cementing process (especially when performing the various functions of squeeze cementing). They
are used to expedite the placement of relatively small volumes of cement slurry through large
volumes of well fluids into a specific, targeted area within a long interval of cased or open wellbore.
Downhole tools are used to isolate this specific area from the rest of the wellbore or to isolate, or
protect, other areas in the well from the cementing process performed in that area. They are used to
control the flow path of cement slurry; spacer fluids and well fluids during the placement and
pressure building phases of the squeeze job. Tools are used to direct the pressure application to the
squeeze zone and prevent its application where it is not needed.
The basic tools in a squeeze tool operator's arsenal are squeeze packers. As mentioned previously,
squeeze packers are grouped in one of two main categories: retrievable squeeze packers and drillable
squeeze packers.

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Retrievable squeeze packers are run, set and retrieved on a workstring. They are constructed of
mostly non-drillable steel alloys. They could be millable, if there is enough time and money (but, then
again, maybe not). Rubberize or rubber-like elastomer sealing elements provide the annular
isolation. Retrievable squeeze packers are intended to be released and pulled from the well after the
job is complete. The cementing process must be planned and executed with their removal being
paramount in importance. Retrievable squeeze packers are often referred to as simply packers.
Drillable squeeze packers, also known as cement retainers, can be run and set on a workstring or
wireline. Obviously, the drillable squeeze packers are constructed of all drillable materials, usually
aluminum alloys, brass, rubber or rubber-like materials, etc. Packer slips are commonly made of
materials like cast iron that are hard so they will bite against the casing wall but will break up into
small pieces when drilled by a bit or mill. When well conditions or required procedures threaten the
ability to remove a retrievable packer, a drillable packer should be used instead.
Drillable squeeze packers (cement retainers) are not to be confused with more recently developed
drillable service packers. Drillable service packers were developed to fill the need for a drillable packer
that performs multiple service functions generally undertaken with retrievable and permanent
packers. Drillable service packers offer the advantage of larger bore sizes with the running and
operational conveniences of the cement retainer. This includes squeeze cementing. However, they
have not replaced the highly reliable retrievable squeeze packers or cement retainers.
For 90% or more of squeeze jobs that utilize a squeeze packer, the job can be completed using either
a retrievable squeeze packer or drillable cement retainer. There are, however, a small percentage of
squeeze jobs where the downhole conditions demand the use of one over the other and selecting the
wrong one can yield disappointing results.
There is a vast array of complimentary and accessory tools that have specific functions, which can be
employed on remedial cement jobs. Most should not be run routinely but only be used when the
need exists. Bridge plugs are mechanical isolation tools that are available in retrievable or drillable
models. Bridge plugs are just that and cannot be pumped through. There is a wide assortment of
products and brand names for service tools that perform the same or similar functions. Care must be
exercised to prevent the misapplication of a particular tool.
A wireline or mechanical bridge plug seals off the zone below the squeeze interval to keep the slurry
from being pumped in, or from freefalling down the casing. Most plugs are drilled after the job.
However, some can be retrieved if they are not cemented in place. Sand is often placed on top of the
plug to prevent it from being cemented and to allow retrieval after the job. This technique is
especially useful for squeezing multiple zones.
When the plan is to reverse-circulate excess cement after placement, operators use a retrievable
packer above the zone. Retrievable packers are equipped with bypass valves that permit complete
circulation of the wellbore (1) while the tool string is being run in the hole, (2) after the packer has
been set, or (3) during reverse circulating after the job.
This circulation capability prevents excessive pressure from being applied to the formation while the
tool string is being run into in the hole, and it prevents the well from being swabbed when the packer
is released and retrieved. Retrievable packers can be either tension- or compression-set and can be
run on wireline or a workstring/tubing. A fiberglass or aluminum tailpipe can be attached to the
bottom of the packer to allow the cement slurry to be spotted close to the zone while the packer is
set well above the zone.
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Drillable packers or retainers can also be used. However, double check-valves are built into these
tools to prevent unwanted flow from either direction. Once the packer is set, a workstring is strung
into the retainer, and then cement is pumped and squeezed below the retainer. The workstring is
then pulled out, and the retainer is closed.
Retainers are often used to help prevent pressure reductions in the wellbore from causing cement
flow back, either after the squeeze job or when the cement is separating zones that have a high-
pressure differential. Setting a retainer between the zones isolates the intervals and permits
operators to squeeze the lower zone and the upper zones in one application.
Bridge plugs. These tools are used to establish a new well bottom anywhere up hole from the existing
total depth (TD). A permanent type tool will establish a new and semi-permanent plugged- back total
depth (PBTD), since it must be drilled out if it is to be removed in the future. When this is not
desirable, a retrievable type is used so that it can be removed by picking it up with the tubing string at
any time. In this case, a few feet of sand fill is placed on top of the bridge plug so the retrieving neck
will not be exposed to the cement. The sand and the cement on top of it must be circulated or drilled
out to expose the tool for retrieval.
Whenever possible, the bridge plug should be pressure tested after it has been set. This will require a
packer in the string to be set just above the bridge plug for the test. When there is no packer, or a
drillable retainer is used, the bridge plug cannot be isolated for a pressure test.

1. Squeeze Cementing Tools

Remedial cementing tools are mechanical or hydraulic devices which are used downhole to assist in
the placement of cement during plug back or squeeze cementing operations. They are generally used
to isolate areas of the casing from treating pressures and cement. Some are available in retrievable or
drillable designs, each being suited for a particular set of well conditions. Remedial cementing tools
are generally provided with service. Details of a specific tool operation, or limitations, should be
obtained from the Service Company or manufacturer.
The choice between a retrievable and a drillable squeeze tool largely dependents on well conditions
and squeeze-pressure requirements.
The main advantage of a retrievable squeeze tool over a drillable/ permanent squeeze tool is its
flexibility.

The advantages of retrievable squeeze tools are:

1. Retrievable squeeze tools can be set and released numerous times in one trip.
2. Less rig time if cement is to be drilled out.
3. Downhole corrections can be made.
4. No setting tools employed.
5. Rugged design.

The disadvantages of retrievable squeeze tools are:

1. Non-drillable metals, sour environment susceptible.
2. No flowback control must use fluid pressure.
3. Reversing of excess cement can potentially disturb the squeeze zone.
4. More complicated in nature than drillable tools.
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12.8.2 Cement Retainers

These tools (Figure 12-25) can be set on wireline, tubing, coiled tubing or slick line. They are placed
above the interval to be squeezed and are drilled out following the waiting on cement (WOC) time.
They should have an internal valve that holds pressure from both directions. Their primary function is
to lock the cement in place during WOC, preventing backflow of cement from the formation or
casing/hole annulus, and preventing feed in of the wellbore fluid. This allows die hole above the
retainer to be wasted clean and tubing pulled before the cement sets.
They are best suited for jobs when:
• Cement slurry may backflow after the squeeze (i.e., placing a column of cement in the
casing/hole annulus or in high-pressure formations).
• Holding squeeze pressure is not obtained and it is desirable to have that stage of cement
set up before trying a second stage.
• Permanently abandoning a zone.
• Weak casing (which can be a problem or either type packer) or other perforations are
nearby.
To set a cement retainer on a wireline, an adapter is used to connect the cement retainer to the
wireline setting tool. The cement retainer is lowered to the proper position and set by electrically
firing a slow burning charge in the setting tool. When the cement retainer is completely packed off,
the setting tool shears free and is retrieved with the wireline. The stinger is connected and run in the
hole with tubing to perform the squeeze. After the tool is set, tubing to allow pumping into the well
below the tool. It is not possible to spot cement. The tool is usually set fairly close to the interval to be
squeezed.
When set on tubing, the cement retainer is connected to a tubing setting tool. The valve is open to
allow the tubing to fill as the cement retainer is lowered. Rotating the tubing to the right releases the
upper slips and initiates pack-off in some models. The tubing is then pulled to complete the pack-off.
When the proper setting tension is achieved, the setting tool shears free. The setting tension may
range from 18,000 lb (9 tons) for 4 ½ in. sizes to 48,000 lb (24 tons) for 9 5/8 in. sizes. The valve is
pushed open by lowering the tubing, and closed by raising the tubing.

Figure 12-25 One Trip Cement Retainer

Baker Hughes K-1 Cement Retainer

Application
The K-1™ cement retainer (Figure 12-26) is the most versatile squeeze tool in the industry. The K-1 is
available in most casing sizes and has an optional sliding valve or flapper valve pressure containment
device. The K-1 can be set on wireline or threaded pipe utilizing Baker Hughes successful line of
setting tools.
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The K-1 cement retainer’s two-way valve is controlled from the surface; no springs to cock or stick;
just pick up to close; set down to open. Maximum clearance for fast running plus improved drilling
ability and pressure ratings make it the right choice. Appendix 12-A (Table 12-5) gives technical details
of K-1 cement retainer.

Features/Benefits

 Tubing or electric line set — can be set by mechanical or hydraulic methods on tubing or drill
pipe or run and set on electric line.
 Faster, safer run-in–run-in speed is up to the operator — Baker Hughes’ locked construction
design and larger clearance make this possible.
 Tests tubing–tubing can be tested before squeezing by picking up to close the valve and
applying pressure.
 Holds final squeeze pressure — automatic closing of the valve when picking up or removal of
stinger, ensures holding the squeeze under final pressure as cement is circulated out.
 Isolates squeeze from hydrostatic pressure — keeping hydrostatic pressure off the zone just
squeezed is important, especially for cementing low-fluid-level wells in batch-squeeze
operations–Baker Hughes’ unique valve guarantees an effective seal.
 Fast drillout–new material specifications developed especially for the K-1 cement retainers
result in faster drillout.
The K-1 cement retainer is available with two different durometer packing elements for oilfield use.
For well temperatures up to 225°F (107.22°C) a 70 Hd packing element can be used. For well
conditions from 100°F (37.78°C) — 400°F (204.44°C) a 90 Hd packing element is recommended.

Figure 12-26 K-1 Baker Hughes cement retainer

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12.8.3 Squeeze Packers (RetrievablePackers)

These squeeze tools are run in the well at the end of the tubing. Once the squeeze job is performed,
the tubing and packer are pulled from the hole. The packer can be set and unset several times on a
single trip in the hole, such as when searching for a hole in the casing or when squeezing multiple
intervals. There are other advantages to using a retrievable packer, such as:
• Allowing cement slurry to be spotted (by using tailpipe).
• Permitting excess slurry to be reversed out after the squeeze is obtained.

There are two major limitations of this tool:

• If they are inadvertently stuck in the hole, they are difficult to drill up due to their design.
• A standing squeeze pressure must be obtained and cement mast be firmly held in place
by wellbore hydrostatic pressure before the tubing can be raised or pulled from the well.
This requires sufficient slurry dehydration to form a strong cement filter-cake that will
withstand the swabbing action of pulling the packer up hole, as well as the differential
pressure between reservoir pressure (or annulus fluid) and the head of the fluid inside the
casing.

Tension-type packers are often used in shallow wells (above 600 to 900m). They require downward
movement and rotation for release. So it is better to use compression (set-down) tools, which
require only a straight pick up for release. Tension packers should be reserved for those situations
where the combined tubing weight and annulus pressure are less than the anticipated squeeze or
pump-in pressure.

Generally 4500-8000 kg (10000 to 15000 lb) is the minimum weight or tension required to pack off
the elements of either compression or tension packers.

The detailed technical data for all packer used in OMV Petrom are described in Chapter 5 (Well
Recompletion Best Practice).

4. Drillable Bridge plug

Halliburton EZ Drill Bridge Plugs (Figure 12-27) are built from cast iron, brass, aluminum, and rubber
to provide unsurpassed drillability in general oilfield service operations. More technical details are
shown in Appendix 12-A (Table 12-7 and Table 12-8).

Operators can use one of the following types of equipment to set EZ Drill Bridge Plugs:
 Electric wireline setting tools,
 Slickline setting tools,
 Coiled tubing setting tools, and
 Mechanical setting tools.

Features and Benefits

• Downhole pressure control and drillability,
• Drill-up with conventional tricone drill bits or junk-style mills,
• Drilling technique and bit choice will affect drilling efficiency, and
• Top drilling.

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Figure 12-27 Halliburton Bridge Plug

Baker Hughes N-1 Bridge Plug- Wireline and Mechanical Set

The N-1™ bridge plug (Figure 12-28) is a high performance drillable bridge plug suitable for almost any
temporary or permanent plugging operation. The plug is constructed from selected materials which
provide a combination of strength and drillability. It can be converted to a K-1™ cement retainer by
changing out the guide and replacing the bridging plug with the correct valve assembly.

Features/Benefits
 Easily convertible from wireline set to mechanical set by adding a shear screw and changing
the upper slip
 Swab resistant element design allows faster run-in speed
 Constructed from readily drillable materials to minimize drillout time

Baker Hughes NC-1 Bridge Plug Wireline and Mechanical Set

The NC-1 bridge plug (Figure 12-28), a modified “top venting” N-1, is for use primarily in gas wells. The
design of the bridge plug allows the upper portion of the body and the bridging plug to be drilled out,
permitting pressure equalization across the tool before drilling out the upper slips. A shear ring
mechanism is used in the wireline set to minimize the amount of material to be drilled out by the
center of the drill bit. Detailed technical specification is presented in Appendix 12-A (Table 12-6).
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Packing Element Selection for N-1, and NC-1 Bridge Plugs

The N-1, TV-10, S and NC-1 bridge plugs are available with two different durometer packing elements
for oilfield use. For well temperatures up to 107.22°C (225°F), a 70 Hd packing element can be used.
For well conditions from 37.77°C (100°F) — 204.44°C (400°F), a 90 Hd packing element is
recommended.

Figure 12-28 N-1 and NC-1 Bridge Plugs

12.9 Surface Equipment for Remedial Cementing

Squeeze Manifold

The squeeze manifold (Figure 12-29a) monitors and controls fluid pressure and movement during
squeeze cementing operations. It also puts all the valves and pressure gauges in one place so the
operation can be conducted with good control and communication.

They are rated for a standard pressure range of 0 to 16.000 psi (1100bar). Display resolution is +/- 10
psi with an accuracy of 0.5% of full scale over a temperature range of 14°F to 176°F (-10°C to 80°C).

A tubing swivel (Figure 12-29b) provides a means of rotating the tubing string with the high-pressure
pump discharge line connected to the swivel. This method is primarily used in conjunction with ser-
vice tools where circulating is required or other treatments performed with the treating line
connected (such as setting and releasing packers, opening and closing bypass tools and squeeze
cementing).

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Figure 12-29 a) Squeeze Manifold; b) Tubing Swivel

12.9.1 Mixing Equipment

Cement slurry may be mixed and pumped downhole continuously or semi continuously or it may be
batch-mixed. The mode chosen depends on the application. Continuous mixing refers to mixing and
pumping slurry at the same time. Batch-mixing refers to mixing all of the slurry first and then
pumping.

Figure 12-30 Cement Mixer

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Continuous mixers have been invented to eliminate cutting sacks and mixing by hand. The first of
these mixers was the jet mixer. Later improvements have given mixers such as recirculation mixer.
Continuous mixing sometimes allows cement that is not mixed correctly to be pumped downhole.
Batch-mixing has been designed to prevent this problem. However, batch-mixing requires more
surface equipment, which increases the cost. The latest move is to go back to continuous mixing, but
with computers automating the system to prevent improperly mixed cement from being pumped
downhole.

A typical continuous mixer is shown in Figure 12-30.

12.9.2 PumpingEquipment

Pumping Equipment
Cement is normally pumped with a triplex positive-displacement pump. Triplex pumps are boosted
with centrifugal pumps. Centrifugal pumps impart a great deal of shear to the slurry, which is
beneficial for mixing. Triplex pumps are low shear but pump at high pressures. Sometimes the
displacement pressures for a cement treatment can be several thousand psi and triplex pumps do
quite a good job in these cases. The number of pumps will depend on the required rate and
anticipated pump pressure. A typical mobile pumping unit is shown in Figure 12-31.

Figure 12-31 Pumping Unit

Bulk Equipment
For land operations in areas with existing oil fields, most cement is dry blended with additives that
give cement the required performance properties. The blended cement is hauled to the location,
mixed with water, and pumped downhole. For remote locations and offshore operations, the
additives are normally taken to the well as liquids, mixed with the water, and then mixed with the
cement. When liquid additives are used, the cement mixing equipment is normally equipped with a
liquid additive device that allows accurate metering of liquid additives into the mix water during
cement mixing operations. A typical bulk unit is shown in Figure 12-32.

Figure 12-32 Bulk Equipment

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12.10 Quality Assurance and Safety Requirements for Remedial Cementing

12.10.1 Remedial Cementing Quality Control and Job Evaluation

The need to evaluate the results of a squeeze job is determined by the requirements of the
subsequent operations to be performed on well. Increased pressure response indicates that a seal
was obtained. This pressure can be applied either by pumping into the well (positive differential into
the well) or by reducing hydrostatic pressure in the wellbore through the use of swabbing or
introducing a lighter fluid into the wellbore (negative differential into the well).

Positive Pressure Test

After the WOC time has elapsed, it is a common practice to test the plugged perforations. However,
this must not be considered as a test of cement ability to hold the formation fluid in place: rather that
the test serves as a method to diagnose a gross failure of the squeeze treatment.
The pressure applied at the face of the perforations is predetermined at the job-design stage. It may
be the reservoir pressure, but should not exceed the formation fracturing pressure.
It is known that mud filter cake would withstand over 5,000 psi (350bar) of differential pressure when
applied from the wellbore toward the formation. Yet the same filter cake cannot withstand a
significant differential pressure when applied from the formation toward the wellbore.
Negative Pressure Test
The universally recognized technique for confirming whether the cement in place will hold the
formation fluids under producing conditions consists of applying a negative differential pressure on
the face of the plugged perforations. The following steps accomplish this:
• Circulating a light fluid (i.e., through a concentric pipe),
• Swabbing the well, and
• Running a dry test.
If sealing achieved in the perforations is complete, no inflow should be recorded on the test pressure
chart.

Acoustic log
When the objective of the squeeze is to repair a primary cementing job, the normal cement bond logs
(CBL) should be run to evaluate the effectiveness of the repair by comparing pre-squeeze and post-
squeeze jobs.
However, traditional cement evaluation using CBL tools and any Ultrasonic tool has severe limitations
when used to evaluate foamed cements. Foamed cement impedance values can be less than those of
annular fluids, such as mud or water. Conventional interpretation of this data might be misleading.

Temperature Profile
The temperature log measures the incremental temperature changes continuously while the tool is
lowered into the hole. This will result in a temperature curve with changes that may indicate
producing or non-producing perforations, cement tops or gaps, casing leaks, or fluid channeling. The
determination of cement tops is the most common use of the temperature survey.

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Radioactive tracers
Radioactive materials can be added to the cement slurry while pumping. Then, subsequent tracer
surveys can indicate whether the cement is in the desired interval. Iodine, iridium and scandium (I131,
Ir192 and Sc46) are appropriate because of their short half-lives (8 days, 75 days and 85 days,
respectively). The iridium and scandium radioisotopes are preferable, because iodine (present as
iodide) is soluble and can be squeezed out of the cement with the filtrate.

Cement Quality Control Guidelines

Before sampling the cement, the real starting point for a successful cementing treatment is to
determine accurately the temperature of well bottom-hole. Then use that temperature and calculate
the bottom-hole circulating temperature. Accurate measurement of bottom-hole temperature and
bottom-hole circulating temperature can be the difference in a highly successful cementing treatment
and a complete failure. A matter of 20-30°F (11-22°C) can make a tremendous difference in
thickening time, compressive strength development, and/or the possibility of gas breakthrough of the
cement, negating the cement barrier.
Most cements are designed to be run with a specific amount of water. It is strongly recommended not
to exceed the ranges of the water ratio. If too little water is used, then the cement slurry will be
extremely viscous, and incomplete reaction will occur. If the water ratio is too high, then the cement
ends up very thin, and there will be free water and settling of the cement. Therefore, it is required to
stay within a recommended weight range during cementing operations.
Whatever the mixing system, the most important property of the cement is its density going
downhole. Nothing on the treatment is more critical than the cement density. The density of cement
slurry must be within narrow range (+- several %) of the density designed in the laboratory.
Once the blend has been selected, samples should be taken, mixed, and thickening-time tests
conducted on the cement and additives. After the lab samples have been evaluated and approved,
sample and evaluate field blending.
Recommendations should not necessarily just be accepted from the local salesman on cement in a
particular area. It is recommended to investigate lightweight cements as those created by the addition
of lightweight spheres and additionally, combined with these, new generation thixotropic additives.
There is available from service companies today good, high-compressive cements with weights as low
as 9 lbs/gal (1078.44 kg/m3). If hydraulic fracturing operations, acidizing or other potentially
destructive practices are going to be conducted, then it would be best, if possible at all, to use very
heavy, and conversely high-compressive, cement opposite the producing zone.
A good rule-of-thumb is to utilize across the producing interval as good quality cement as possible. If
acidizing or fracturing operations are going to be conducted and if there is a possibility of channeling,
fracturing, or etching is going to occur, then it is necessary (if possible at all) to utilize cements that
will approach the strength of the formations that they are being used to isolate.
Once the field blend is in place in bulk storage, obtain representative samples for laboratory testing
prior to pumping the cement.
Any loss of circulation needs to be controlled. If the lost circulation is due to fracturing, then redesign
the treatment so the hydrostatic head of cement is less than the fracturing pressure. Solutions to loss
circulation problems involve the use of lightweight additives, lightening the fluid column ahead of the
cement or to foam the cement.
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In every way possible, it is always advisable to accomplish zonal isolation without the use of foam
cement.
With the new microprocessor control systems available, it is absolutely essential that post-job
inventories are done to ensure that all additives have been pumped in the well.
Too light cement, along with the problems of free water and poor compressive strength, can cause
the well to be out of control if you are trying to cement in a balanced state, too heavy cement can
cause high-viscosity problems, poor quality cementing, and could cause the formation to be fractured.
As in a fracturing treatment, check all bulk storage equipment and chemicals before the job begins.
Check after the treatment to be sure that all the additives that were to be pumped were indeed used.
Many jobs have been conducted where less than one-half of the cement or other additives were
pumped.
Some of the problems are related to the lack of any quality control or supervision of cementing
treatments. Although a great deal of care has been taken in measuring thickening time, compressive
strength of cements prior to the treatment, little or no supervision was done on the job site. Primarily
request is to assure that the cement is the correct weight that all additives are added correctly, and
the pump rates follow the predesigned schedule.
The casing and tubing string should be as internally clean as possible (free of rust, paraffin, scale,
perforation burrs, etc.). Blowout preventers (BOP) should be tested to the maximum expected
pressure.
If squeeze work is to be performed through casing, it is necessary to calculate the internal yield
pressure and joint strength of the easing. If squeezing is to be performed through tubing set inside the
casing, calculations must be made for the tubing and the casing, allowing the collapse resistance of
the tubing.
Since compressive strength is a function of the water/solids ratio, high-density (low water/solids ratio)
slurries are best suited for such plugs. Addition of sand or weighting materials will not improve the
compressive strength of lower water content slurry. On the other hand, lost circulation or plug- back
jobs may require viscous low-density slurries to avoid losing the plug in the formation.
A cement plug is best set in a competent hard rock. Shale should be avoided as it is often caved and
out of gauge. Ideally, the plug should extend from soft shale down to a hard formation. In any case,
the logs and the drilling rate record should be consulted when selecting a location to set a plug.

It is recommended that the slurry pumping time is equal to the anticipated job time plus 30 minutes.
Whenever possible, spacers and washers should be pumped in turbulent flow conditions. If turbulent
flow is not feasible, plug flow spacers are perfectly acceptable
It is recommended that the pipe is carefully centralized. This precaution can dramatically improve
mud removal. Pipe rotation is also cited as an advisable practice.
The slurries must be designed for a thickening time in accordance with well conditions and job
procedures, plus a reasonable safety factor. The recommended practice is that ample waiting on
cement time (WOC) be allocated in the range 12 to 24 hours. Since the well temperature for a cement
plug job is difficult to know accurately, a common practice is to allow longer WOC times.

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Slurry densities usual range from 1.87 g/cm3 (15.6 lb/gal) to 2.10 g/cm3 (17.5 lb/gal) is preferable to
ensure good compressive strength development.

Design the cement slurry, optimizing thickening time, compressive strength and free-water content.
Conduct lab testing of the blend, using lab samples at bottomhole temperature and pressure (BHTP)
conditions.

Obtain samples of the field-blend cement and evaluate them at BHTP conditions.

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Appendix 12 - A Cement Retainers and Bridge Plugs Specifications (used in

OMV Petrom)

Table 12-5 Baker / Hughes K-1 Cement retainer specification

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Table 12-6 Baker N-1 and NC-1 Bridge Plugs Specification Guide

N-1 AND NC-1 BRIDGE PLUGS SPECIFICATION GUIDE

Casing
Plug OD
OD Weight Size
in mm lb/ft kg/m in mm
4 1/2 * 114.3 9.5-16.6 14.1-24.7 1AA 3.593 91.3
5 127 11.5-20.8 17.1-31.0 1BB 3.937 100.0
51/2 139.7 14-23 19.3-34.2 2AA 4.312 109.5
14-26 20.8-38.7 2BB 4.937 125.4
6 152.4
10.5-12 15.6-17.9 3AA 5.410 137.4
65/8 168.3 17-34 25.3-50.6 3AA 5.410 137.4
32-44 47.6-65.5 3AA 5.410 137.4
7 177.8
17-35 25.3-52.1 3BB 5.687 144.4
75/8 193.7 20-39 29.8-58.0 4AA 6.312 160.3
85/8 219.1 24-29 35.7-72.9 5AA 7.125 180.9
95/8 244.5 29.3-53.5 43.6-79.6 6AA 8.125 206.3
60.7-81 90.3-120.5 6BB 9.000 228.6
103/4 247.6
32.75-60.7 48.7-90.3 7AA 9.437 239.7
60-83 89.3-123.5 7BB 9.937 252.4
113/4 298.5
38-60 56.5-89.3 8AA 10.437 265.1
85-102 126.5-151.8 8BB 11.562 293.7
133/8 337.7
48-72 74.1-107.1 9AA 12.000 304.8
109-146 162.9-217.2 11AA 13.915 353.4
16 440.4
55-84 81.8-125.0 11BB 14.585 370.5
* N-1: In 4-1/2 in. (114.3 mm ) 9.5 lb (14. 1 kg/m) casing, when a no. 10 setting
tool is not available, a size 20 setting tool and size 2AA adapter
kit may be used when wellconditions permit.

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Table 12-7 Halliburton EZ drill Bridge Plug Specification Guide

EZ Drill Bridge Plug

Part Number Casing Casing Casing Casing Maximum Minimum
Tool Size Size Size Weight Weight Casing ID Casing ID
in. (mm) in. mm lb/ft kg/m in. (cm) in. (cm)
4 101.60 Line Pipe Line Pipe
100004414 41/2 114.30 9.5-13.5 14.1-20.09
803.639 43/4 120.65 16 23.81 4.18(10.62) 3.92(9.96)
4 1/2 (114.3) 5 127.00 20.3-24.2 30.2-36.01
51/2 139.70 36.4 54.16
5 127.00 Line Pipe Line Pipe
100004416
51/2 139.70 13.00-23.00 19.34 - 34.22
803.643 5.04(12.80) 4.67(11.86)
53/4 146.05 22.50-25.20 33.48-37.50
5 1/2 (139.7)
7 177.80 64.1 95.39
6 152.60 Pipe Line Pipe Line
100004417 65/8 168.40 17.00 - 24.00 25.29-35.71
803.649 7 177.80 20.00 - 38.00 29.76-56.55 6.46(16.41) 5.90(16.99)
7 (177.8) 75/8 193.80 45.30 - 55.30 67.41-82.29
73/4 196.85 53.52 79.64

Table 12-8 Drill Bridge Plug Operation (Halliburton)

EZ Drill Bridge Plug Operation

Nominal Nominal Maximum Maximum Recommended
Casing Casing Recommended Pressure Differential
Size Size Temperature psi (MPa)
in. mm °F (°C)
Applied Above Applied Below
41/2 114.3 425(218) 10000(68.95) 7000(48.26)

51/2 139.7 425(218) 10000(68.95) 7000(48.26)

7 177.8 425(218) 10000(68.95) 8000(55.16)

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List of Figures

Figure 12-1 Depleted zone abandonment,

Figure 12-2 a) Gas Coning; b) Gas Fingering; c) Moving G/O contact,

Figure 12-3 Moving oil/water contact,

Figure 12-4 a) Water coning; b) Water fingering,

Figure 12-5 Zonal isolation Workflow,

Figure 12-6 WF Remedial cementing classification,

Figure 12-7 Low pressure squeezing,

Figure 12-8 Squeezing fractured zones,

Figure 12-9 Probable result of high-pressure cement squeeze job,

Figure 12-10 Cake permeability and dehydration rate of slurry,

Figure 12-11 Cement plug placed by balanced-plug placement method,

Figure 12-12 Cement plug placed by Dump Bailer,

Figure 12-13 Two plug method,

Figure 12-14 Cement plug placement workflow,

Figure 12-15 Braden head placement technique,

Figure 12-16 Squeezing cement through tubing with pressure lower than formation fracturing
pressure,

Figure 12-17 Bridge plug with cement packer,

Figure 12-18 Drillable cement retainer set and/or operated on wireline, tubing or coiled tubing,

Figure 12-19 A typical pressure chart of a hesitation squeeze,

Figure 12-20 Squeeze cementing through tubing, packer or cement retainer,

Figure 12-21 Squeeze cementing through tubing, packer or cement retainer (continuation),

Figure 12-22 Squeeze cementing through tubing, packer or cement retainer (continuation),

Figure 12-23 Isolating of the production interval (one zone),

Figure 12-24 Isolating of the production interval (two or more zones),

Figure 12-25 One Trip Cement Retainer,

Figure 12-26 K-1 Baker Hughes cement retainer,

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Figure 12-27 Halliburton Bridge Plug,

Figure 12-28 N-1 and NC-1 Bridge Plugs,

Figure 12-29 a) Squeeze Manifold; b) Tubing Swivel,

Figure 12-30 Cement Mixer,

Figure 12-31 Pumping Unit,

Figure 12-32 Bulk Equipment.

List of Tables

Table 12-1 Application of API Classes of Cement,

Table 12-2 Cement properties for various types of squeeze application,

Table 12-3 Cement properties for various types of plug application,

Table 12-4 Remedial cementing planning, designing and executing processes,

Table 12-5 Baker / Hughes K-1 Cement retainer specification,

Table 12-6 Baker N-1 and NC-1 Bridge Plugs Specification Guide,

Table 12-7 Halliburton EZ drill Bridge Plug Specification Guide,

Table 12-8 Drill Bridge Plug Operation (Halliburton).

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References

1. American Petroleum Institute, Std.API/Petro RP 10B- Recommended Practice for Testing Well
Cement, API Recommended Practice 10B, twenty-Second Edition, December 1977.
2. Erik B. Nelson, Well cementing, Schlumberger Educational Services, Texas 1990.
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And Stimulation, Four Edition, OGCI and Petro Skills Publications, Tulsa, Oklahoma 2003.
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Remediation Handbook, 2004 by Gulf Publishing Company, Houston, Texas.
6. Bellarbz Johnathan: Well Completion Design, Elsevir 2009
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Well Cementing Practices in the United States, New York, 959, pg. 149-159.
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Jobs." SPE 90113,1990.
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Cementing Job," Oil & Gas Journal. December 13, 1982, pg. 71-74.
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Remediation-HANDBOOK
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The Systems Approach," Petroleum Engineer, September 1981. pg. 116-30.

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22. Purvis, D and St. Clergy, J.: "Eliminating the Unknowns of Primary Cement with On-Site
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 Quality Assurance and Safety Requirements for Remedial Cementing in OMV Petrom.
 RC Selected Best Practices Cases in OMV Petrom
o Detailed technical programs for the wells: l Lipanescu 311, Tazlau 278, Tazlau 113
and Oprisinesti 620, Coltesti 39, 4335, 4336 and 4338 Mamu, 1311
Independenta,
 Remedial Cementing Best Practices Reports (Design and Program, Laboratory test,
control, execution, HO).
 Well/Casing Repair WO Best practices in OMV Petrom (346 Ciuresti S)
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28. Teknica : Well Operations: Workovers. Februarz 2001, Course materials
29. Wan Renpu: ADVANCED WELL COMPLETION ENGINEERING. Third Edition, English translation
# 2011, Elsevier Inc. All rights reserved

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