primary cementing repair (squeeze...
TRANSCRIPT
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Cementing Basics
• Primary Cementing
• Repair (Squeeze Cementing)
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Why Cement?
• Completes the isolation step that was started with casing.
– Pressure isolation
– Pipe support and protection
• Exterior corrosion
• Pressure control
• Load and force application support
– Leakoff control – prevents crossflow?
– Water influx control
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Statistics
• Primary cementing cost about 5% of well cost.
• About 15% of primary cement jobs require squeezing
• Total cost of cementing when squeezing is required is about 17% of well cost.
• Typical number of squeezes required to fix a problem in a primary cement job = 3.
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Cement Circulation
• Path: Down the casing and up the annulus
• Concerns:
– Cement density vs. pressure “window” from formation
– Cement bond between pipe and formation
– Cement pump time
– Ability to place the cement over the whole column
(fluid loss control, correct volumes, pumpability)
– Cement strength development
– The quality and longevity of the seal.
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Equivalent Circulating Density
16
ppg
Friction
Pressure
18 ppg effective
mud weight?
Cement is a
viscous, dense
fluid. The problems
are ineffective
displacement of the
mud and attaining a
full column of
uncontaminated
cement.
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How far is cement brought up the annulus?
Minimum
200 to 500
ft above
the shoe
Is the cement brought
to surface? –
Unlikely.
Why?
1. Fracture gradient
is usually 0.7
psi/ft, cement
density is 0.85
psi/ft.
2. Time
3. Cost
4. Not
understanding
protection need.
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The most important section
of the cemented column is
near the casing shoe. – The
strength at this point must
be sufficient to withstand
the highest weight mud that
will be used in the next
section to be drilled.
After cementing, the
well is drilled ahead for
a few feet and a “shoe-
test” is done to simulate
the highest mud weight
expected. If the shoe
breaks down, it must be
squeezed until it passes.
The integrity of the shoe is the driller’s first concern in cementing. In
the PE world, cement integrity concern includes pressure, water and
exterior corrosion isolation. The height of “good” cement bonding is a
primary failure cause in well failures.
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Neat (no additives) cement is a manufactured product with a specific
grain size and properties. The slurry properties for the well are made to
order by incorporating a range of additives into the mixed slurry that
affect pump time at temperature, fluid loss control, stability to thermal
conditions, and gas migration.
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API
Cement
General Use Temperature
(Neat Cement)
A Construction Grade, strong, surface and cool
operations
Surface and
shallow apps.
B Surface to about 6,000 ft (1830m) when
conditions require moderate sulfate resist.
110oF
C Finer Grind, high early strength, To 6,000 ft
(1830m). Used for water control.
140oF
D 6,000 to 10,000 ft (1830 to 3050m), HTHP. 170 to 230oF
E 10,000 to 14,000 ft (1830 to 3050m), HTHP. 230 to 290oF
F 10,000 to 16,000 ft (1830 to 4880m) extr. HPHT 230 to 320oF
G A basic cement for surface to 8,000 ft (2440
m) as manufactured. More range w/ additives
80 to 200oF
H A basic cement for surface to 8,000 ft (2440
m) as manufactured. More range w/ additives
80 to 200oF
J For use from 10,000 to 16,000 ft (1830 to
4880m), extr HPHT
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The final slurry design has a certain slurry density, usually between 11
and 18 lb/gal, with typical class G or H being about 16.4 lb/gal. More
water can be added, but the water will separate as it sets, resulting in
channels or weak cement.
Fluid Density Balance – used
to get fluid density in lb/gal
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Every cement design
must take into account
the temperature and
pressure extremes in the
well. Low temp retards
the cement set time.
High temp accelerates the
cement set time.
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Temperature vs TVDss
-11500
-10500
-9500
-8500
-7500
-6500
-5500
-4500
-3500
-2500
-1500
-500
0 20 40 60 80 100 120 140 160 180 200 220 240 260
Temperature (degF)
TV
Ds
s
Seal-A-01 MTEMP3
Seal-A-01 MTEMP4
Seal-A-01 MTEMP5
NS29 MTEMP
NS27
Top of Slush Zone
Base of Slush Zone
Top of Permafrost
Base of Permafrost
Effect of Permafrost on
temperature profiles –
Alaska Well
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Modifying the Set Time of the
Slurry
• Accelerators speed it up.
– calcium chloride
– sodium chloride
– gypsum
• Retarders slow it down
– lignins, sugars, cellulose
– some drilling muds
– sodium chloride
The sodium chloride
may be an accelerator or
a retarder, depending on
amount of salt and other
factors.
The effect of mud on the
set time of cement is
unpredictable.
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Cement without a retarder in a hot formation will set up too rapidly;
often before the cement has been completely displaced into the annulus.
Increasing temperature makes the cement set up more quickly.
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Cementing Problems That Must
be Addressed in the Design 1. Well Control – until the cement sets, it must control
the pore pressure.
2. Pumpability – slurry pump time must be long enough to completely displace cement.
3. The mud cake must be removed to get the cement to form an effective seal with the formation.
4. Fluid Loss Control (after mud cake is gone – If the cement dehydrates, it cannot be pumped.
5. Communication control (avoiding channels)
6. Invasion of natural fractures in the pay by cement.
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Well Control
• Working in the slurry density “window”
– Pore pressure and wellbore stability establishes
the lower limit of slurry density.
– Fracturing gradient establishes the upper limit
of slurry density.
• Cement density normally is 16.4 lb/gal
– Typical light weight cement is 11 to 12 lb/gal
– Heavier weight cements may be up to 23 lb/gal
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Light Weight Cement
• Methods
– Add more water – poor method, often creates free water channels and pockets
– Finer grind cement – allows more water addition and keeps the water in the cement
– Light weight fillers
• Small (10 to 70 micron), air filled “balloons” such as ceramic or glass
• Foamed Cement
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Heavy Weight Cement
• Densities to 23+ lb/gal
– Sand
– Hematite
– Iron carbonate
• Hazards?
– Frac pressure
– Equivalent circulating density
– Cement set times
– Fluid loss
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Cement Problems and Failures
• Problems? – Cement at shoe not strong enough to contain pressure
of deeper zones– must repair before drilling ahead.
– Casing not centralized – leaves mud channel on low size. May leak now or later. Requires squeeze.
– Cement mixed with too much water causing channel along the top of the hole.
– Casing not moved during cementing (sometime impossible in deviated wells) – you need to get mud displacement by cement to get a good job.
– Not enough cement in annulus to function as a barrier.
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Well Failure Statistics
0%
5%
10%
15%
20%
25%
30%
35%
0.0 5.0 10. 15. 20. 25. 30. 35. 40.
# Years of Well Life prior to Casing Leak
Cu
mu
lati
ve %
Well
s C
om
ple
ted
Develo
pin
g C
asin
g L
eaks
'94-2000'
'90-'93
'80-'89
'70-'79
'58-'70
Vastar Putnam
Wells D
evelo
pin
g L
eaks
Well Life Prior to Casing Leak, Years
The effectiveness of the cement is a major factor in well life without leaks. Note the
small percentage of failures, even on 30+ year old wells in Putnam field.
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Common contaminants and ops
that degrade cement bond ? • Slurry contamination – primarily mud during
displacement.
• Failure to remove the mud cake.
• Sulfate effects on mixing slurry and on set cement – use
sulfate resistant cement.
• Acids – HCl – no effect. HF – significant local effect – but
shallow without channels.
• Explosives (perforating) – usually minor effect if there are
no mud channels.
Typically, if a cement job “breaks down” after perforating, acidizing,
solvent, or frac, the problem is that an existing mud channel in the
cement has been disturbed.
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Dehydration of the slurry
causes a plug in the
annulus.
Since the first objective of
a cement displacement is to
remove the mud filtercake,
the increased fluid loss has
to be controlled by the
cement slurry.
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Low strength formations
(low fracture gradient) pose
a special problem.
Created or natural fractures
can be a thief zone for
whole cement – causing
less height in the annulus.
Natural fractures can also
act as a fluid loss site for
leakoff for water from the
cement – the result is
dehydration of the cement
slurry.
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Fluid loss through wide natural fractures is often very hard to
control – requiring particulate and/or flake fluid loss control
additives.
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Salt zones can create
cavities or washouts.
If a salt water slurry is
used, the salt must be
checked with pumpability –
the salt can be an
accelerator or a retarder.
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Cement Displacement
• The first part of the cement slurry is contaminated
by cement. Contaminated cement will not set up.
• Where does the mud contamination come from?
– Mud system in the annulus
– Interior pipe walls
– Open hole – filter cake
– Washouts and cavities
• Now, what can you do to prevent contamination?
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Basic Mud Cake Removal
• Physical – scratchers, rotation, reciprocation
• Chemical – dispersants, sweeps, solvents
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Mechanical removal devices such as scratchers and scrapers require pipe
movement, which is frequently not possible in high torque and drag
instances. They also introduce easily breakable parts into the wellbore.
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Chemical Flush Basics
1. Base fluid condition
2. Dispersant
3. Sweep
4. Spacer
5. Cement
Mud
Base fluid
Dispersant
Sweep
Spacer
Cement
Displacement
A properly designed flush focuses on time
of contact, fluid mixing, lift of solids and
avoidance of cement contamination.
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Displacement and Pill Design
• must be designed to obtain effective mud displacement & water wetting of casing. Keys:
– disperse and thin the drilling fluid
– lift out debris and junk
– water wet pipe
– remove debris (mud cake, pipe dope, scale, etc.)
– effectively displace the mud
– allow uncontaminated cement to reach the desired height.
Source: Wellcert
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Brines for Mud Displacement
1. A thinning base fluid flush.
2. An effective brine transition system must further thin
and strip the mud and create wellbore displacement.
3. A carrier spacer must sweep out the solids and clean any
coating from the pipe or rock that could cause damage
problems.
4. A separation spacer must do the final cleaning and
separate the residual mud from the brine.
5. The brine must sweep the spacer out. At this point the
well should be clean. Fluid loss may be high!
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Cleaning and Transition Spacers
Spacer Type Function Minimum
Coverage
WBM OBM
Base Fluid Thin & mud
condition
250 to 500 ft Water Base oil
Transition Mud to spacer,
cuttings
removal
500 to 1000’ Viscous pill Viscous Pill
Wash Clean pipe 500 to 1500’ Water+ WBM
disp. surfactant
Oil + OBM
disp. surfactant
Separation Separate WS
from brine,
solids removal
500 to 1000’ Viscous pill Pill?
Completion
Fluid
Completion
fluid
Fill Completion
Fluid
Completion
Fluid
9-5/8” casing in 12-1/4” hole, annular area = 0.3 ft2
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Brine Flush Contact Times
For Pump
Rate, bpm
Annular
Velocity,
ft/min
Barrels
Pumped
Column
Length, ft
Contact
Time,
minutes on
one foot.
8 150 200 3743 25
10 187 400 7486 40
12 225 400 7486 33
9-5/8” casing in 12-1/4” hole, annular area = 0.3 ft2
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Removal of the Mud Cake
• Part of the mud cake does not contribute to the fluid loss control. Removing these particles from the completion cleans the well.
• Approximately 80% of the outer layer of the cake can be removed in some muds without affecting fluid loss.
• Removal by velocity is often very effective. Even more effective with a dispersant.
300 ft/min or 92 m/min
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Flow profile in a well with decentralized pipe. Note That most
of the flow comes along the top of the pipe. This affects
cleanup and residence time of the fluid on the wellbore. The
lower section of the wellbore may remain buried in cuttings
and never have contact with any of the circulated fluids.
Centralizing the pipe and rotating the pipe (reciprocating too) help!
Major flow area
Very low
velocity or no
movement
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How can you tell if the entire hole is
being circulated?
• Displacement marker sweeps.
– Dye, grain, colored beads, etc.
– Time their travel – compare to calculated
sweep.
Fast marker arrival at
surface, entire hole is
not being swept –
expect channels in
the cement.
Marker arrival at
near expected
time, hole sweep
is near ideal.
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Displacement of the annulus to displace fluids and mud cake depends
partly on velocity.
The annulus changes as casing replaces the drill string. As the annular
space decreases – velocity for any rate increases in the smaller area and
the back pressure on the bottom hole may also increase – rates may have
to decrease to avoid high ECD’s (equivalent circulating densities).
Circulating down the casing and up the
small annulus can produce very high
friction pressure and raised BHP.
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Cement Displacement in the Pipe
• The Two-Plug displacement system
– Patented and used since about 1915
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A single wiper plug dropping tool, showing “bail” release mechanism.
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The Two Plug System – Helps isolate the
cement from the mud and the
displacement fluid.
The top plug is solid and the bottom plug
is hollow and has a diaphragm that
ruptures when the bottom plug hits the
float collar.
If the plugs are accidentally reversed, the
cement will be trapped in the casing. The
plugs are color coded to help prevent
switching or help diagnose the problem
when a plug is drilled out.
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Every time a plug sweeps through the casing, a small amount of mud and
other debris is pushed ahead of the plug. The contaminated cement in
this area will not set or will set very slowly.
For this reason, a float collar, set a joint above the shoe will keep the
contaminated cement at the end of the displacement inside the casing –
not at the shoe.
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A float valve allows fill of the casing from the hole as the casing is run,
but it must close after the cement has been pumped to prevent U-Tubing.
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Float collars are one to three joints
above bottom depending on the
length of the string and the diameter
of the casing.
This traps contaminated cement
inside the pipe – easily drilled out
later.
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Examples of equipment used on the BHA (bottom hole assembly) during
casing running. The float equipment helps prevent backflow of cement
after full displacement. The guide shoe helps guide the casing past
ledges and doglegs (sudden hole direction changes) during pipe running.
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A float collar. The
valve prevents
backflow of fluids after
the cement has been
displaced. Element
wear during pumping
of large volumes of
cement may cause
failures necessitating
holding pressure on the
well after cement
displacement.
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Use of centralizers improve the ability of the cement to surround the
pipe, displacing the mud and creating a channel-free seal. Centralizers
also assist running casing in deviated sections.
Area of undisplaced mud – a mud channel
remains, requiring squeezing.
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Bow spring centralizer.
This is a deformable, but
normally weak centralizer
that may lose performance
and centralization with
increasing string weight
and increasing wellbore
deviation.
Although popular, they are
poor performers in truly
centralizing the casing
string, especially in
deviated wells.
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Straight vane, solid body
casing centralizer. This is
a slip-over type that floats
between the couplings
unless lock rings are
added.
The efficiency of holding
the casing off the wall
depends on whether the
formation wall is strong
enough to prevent
embedment of the vein
into the face of the
formation.
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Spiral centralizer, assists in decreasing drag and helps centralize casing.
It may also help channel cement in a short lived swirl pattern just
downstream of the centralizer location. These are usually viewed as
highly effective in improving cement isolation.
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Quiz - Cementing
• Calculate the volume of a spacer, if the needed
contact time is 10 minutes over the bottom 3500 ft
open hole interval in a 10,000 ft deep well, pump rate
is 4 bpm, the drilled hole size (gauge) is 10.75” and
the casing is 8.675” (ignore couplings).
• What % of the hole volume in problem 1 is being
circulated if the neutral density tracer appears at the
surface 15 minutes ahead of schedule?