SPE 150751
Challenges and Remedy for Cementing of HPHT Wells in Nigerian Operation
Shado Yetunde and Joel Ogbonna; Institute of Petroleum Studies , University of Port Harcourt, Nigeria
Copyright 2011, Society of Petroleum Engineers
This paper was prepared for presentation at the Nigeria Annual International
Conference and Exhibition held in Abuja, Nigeria, 30 July–3 August 2011.
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Abstract
As hydrocarbons are being depleted from some
formations, the search is on for greater reserves in
difficult regions. Some wells are now drilled in
more hostile downhole conditions, which include
high temperature and high pressure. A well is
considered to be high pressure and high
temperature (HPHT) if the pressure exceeds
15000psi (1020 bar) and the temperature exceeds
o
o
300 F (149 C). The challenges created by these,
make drilling and cementing in these regions
difficult. The study reveals that in order to meet up
with the challenges of HPHT drilling and
cementing operations, issues such as effect of
temperature and pressure, large stresses,
degradation of set cement at elevated
temperature, small ECD windows, efficient fluid
design and displacement among others must be
addressed for successful job execution and
excellent job delivery.
The objective of the study therefore is to highlight
various challenges associated with HPHT wells,
the Best Practices that have been adopted in
several HPHT wells and the way forward. This will
provide a learning point for operators, researchers
and other Engineering professionals especially for
the emerging HPHT operations in Nigeria and Gulf
of Guinea.
Introduction
Primary cementing is a critically important
operation in construction of a well. Apart from
providing structural integrity to the well, the chief
purpose of the operation is to provide a continuous
impermeable hydraulic seal in the annulus,
preventing uncontrolled flow of reservoir fluids
behind the casing. The migration of formation fluid
to the surface can cause a blow out, with
consequent environmental damages and possible
loss of life. This migration can also cause a
contamination of drinking water or can affect nearwell bore ecology (Frigaard and Pelipenko, 2003).
In fact, it is ideal to assume that cementing is the
only consideration for effective zonal isolation.
Cementing in itself can be a bit complicated,
depending on the region drilled and sections
encountered. It is because of these that special
attention is paid to cementing processes
especially in High pressure High Temperature
(HPHT) wells. The secret to zonal isolation is the
good bonding properties of the cement with the
casing and the formation, but this can be affected
by cement shrinking and stress changes induced
by downhole variation of pressure and
temperature.
Recently, more of HPHT wells are being drilled
and with that comes the challenges associated
with these kinds of operations. Ogbonna (2010)
stated that HPHT wells are wells with pressures
that exceed 15,000 psi and temperature that
o
exceed 300 F respectively and are usually located
at depth greater than 15,000ft. Efficient drilling is
not only to drill and get to the reservoir, but to get
there with as little issues as possible. The main
attribute of a successful drilling should be the
complete isolation of all the various zones
encountered. For this to be effective, special
consideration should be taken into the cementing.
2
Challenges in HPHT Wells
The Effect of Temperature. In HPHT wells, the
slurry becomes sensitive to high temperature so
that the thickening time of the slurry is highly
reduced, making the cement set faster than in
average temperature wells. Temperature also
affects the rheological properties of the cement
slurry. Ravi and Sutton (1990) mentioned that the
plastic viscosity (PV) and yield viscosity (YV)
decrease with an increase in temperature.
Accurate prediction of BHCT is also very crucial in
o
cementing, because a change as small as 5 C in
the temperature results in a large change in
thickening time (Frittella et al, 2009). North et al.
(2000) in a paper on a cement case study on wells
in the North Sea outlined that there are two
temperatures of importance in the well and they
are:
Bottomhole Circulating Temperature; this is the
temperature the slurry encounters as it is being
pumped into the well and it is the one that affects
thickening time.
Bottomhole Static Temperature; this temperature
of the formation and it is the temperature the slurry
will be subjected to after circulation has stopped
for a period of time.
The Effect of Pressure. Pressure has effects on
both the well and the drilling fluid and cement
slurry. In cases where the pressure had not been
properly estimated, the selected casing will not be
able to withstand the pressure from the formation,
which will invariably lead to a collapse of the
casing in the well and therefore a kick is
encountered. Weighting agents are used to create
the minimum over balance and they reduce the
pumpability of the cement thereby accelerating the
development of premature compressive strength.
Small Equivalent Circulating Density Window.
As the depth of well increases, the increased
hydrostatic head causes an increase in ECD due
to compression and increase in temperature
causes a decrease in ECD due to thermal
expansion.
The Degradation of Post- Set Cement Due to
High Temperatures.
In HPHT formations, the wells are subjected to
high temperature variations and these changes
affect both the formation and the casings, causing
expansion and contraction. This expansion and
contracting of casing and plastic formation like salt
SPE 150751
causes cracks in the
(Elzeghaty et al, 2007).
already
set
cement
Large Stresses on Post- Set Cement for Life of
Well.
The setting of cement is by the reaction between
water and cement. This process is called hydration
and if it continuous, the pore pressure in the
setting cement reduces with its pore spaces. The
post-set cement consisting of minimal number of
pore spaces when subjected to high loads in deep
wells compression sets in and destroys the
cement sheath by compaction of matrix porosity
(Elzeghaty et al, 2007). This destruction of cement
matrix can be said to be caused by mechanical
failure or damage and they create cracks in the
cement matrix. These cracks are a pathway for the
migration of gas from the formation to the surface,
thereby shortening the life of the well because the
integrity of the cement has been compromised.
Migration of Gas through Cement.
Migration of gas through the cement has been an
industry problem for many years. Al-Yami et al
(2009) pointed out that approximately 80% of wells
in Gulf of Mexico have gas transmitted to surface
through cemented casing.
Strength Retrogression of Cement
For twelve months or more, after cement has set,
it continues to hydrate and consequently develop
in strength. After this time, it maintains the
strength that it has attained except if it is attacked
by agents of erosion. Cement will attain maximum
strength after one fortnight is exposed to
o
temperatures exceeding 230 F. After these first
two weeks, the strength slowly starts to decrease.
This process of cement losing its strength is
known as strength retrogression. Structural
changes and loss of water are the agents of
cement degradation. When cement is set, it
contains a complex calcium silicate hydrate called
o
tobermorite. At temperatures around 250 F,
tobermorite is converted to a weak porous
structure which causes strength retrogression. The
rates at which these changes occur depend upon
temperature(Young and Hansen, 1987).
HPHT Cementing Remedy
Accurate estimation of temperature
monitoring of downhole conditions:
and
Frittella et al (2009) stated that computer basedtemperature simulators is now being used to
estimated bottomhole circulating and static
SPE 150751
temperature. The simulators are run in the casing
with the slurry and it measures the instantaneous
temperature as the slurry moves from surface to
bottomhole. Frittella et al (2009) also mentioned
that the cement simulator is a computer software
program that calculates and shows all job
parameters, such as flow behaviour, Flow rate/
annular velocity and differential pressure. It can
predict the Equivalent Circulating Density (ECD),
displacement efficiency (achieving the maximum
mud displacement out of the wellbore), standoff
value (percentage of casing centralization in the
wellbore), job operation time for proper thickening.
The software is used to optimize the cementing
operation by recommending the best displacement
rate and slurry density (based on ECD behaviour
between pore and fracture density line) the
simulator can ensure that during the cementing job
the downhole pressure neither exceeds the
fracturing pressure of the formation nor drops
below the pore pressure.
Efficient Slurry Design.
For successful cementing of a HPHT well, major
consideration should be given to slurry design and
slurry
placement
techniques.
Specific
characteristics of a particular well dictate the slurry
properties and performance.The slurry should
develop the required properties and isolate the
zones,as well as protect the casing (Biezen and
Ravi, 1999).
The procedure for cementing deep wells are
basically the same as those for shallower wells;
however, such wells are generally considered
critical, because of the more severe well
conditions and higher complexity of the casing
programs (Young and Hansen, 1987). A threestep design process to ensure construction of a
well that ensures a means of safe and economic
production of hydrocarbons is imperative. The
three steps involve engineering analysis, cement
slurry design and testing, and cement slurry
placement
and
monitoring
respectively.
Consequently, the cement system design can be
complex, involving an elaborate array of retarders,
fluid-loss additives, dispersants, silica, and
weighting materials.
Stabilizing of Cement Systems and Stopping of
Strength Retrogression
Strength retrogression, a phenomenon that occurs
naturally with all Portland cements at temperatures
of 230 to 248°F (110 to 120°C), is usually
3
accompanied by a loss in impermeability, and is
caused by the formation of large crystals of !dicalcium silicate hydrate (!-C2SH). Silica flour or
silica sand is commonly used to prevent strength
retrogression by modifying the hydration
chemistry, and it can be used with all classes of
Portland cement. The addition of 30 to 40% silica
is usually adequate to produce a set cement with
low permeability (<0.1millidarcy) that overcomes
the problems of strength retrogression, though
additions can range from 30 to 100%. At high
temperatures, silica causes the reaction with
cement and water to produce xonotlite instead of
tobermorite. Xonotlite is a lot stronger and results
in a significantly smaller increase in permeability
Antigas Migration slurry design for HPHT wells
Gas migration represents 25% of the primary
cement jobs failures. The main purpose of the
annular cement is to provide an effective zonal
isolation for the life of the well in order that oil and
gas can be produced safely and economical. One
of main problems for achieving this objective is
fluid migration in the annular space after well
cementing. The main factor preventing the fluid
from entering the cement is hydrostatic pressure
of cement column and the mud above it. This
pressure must be greater than pore pressure of
gas-bearing
formation to prevent fluid invasion into cement
column. Besides, it must not exceed fracturing
pressure of the formation to avoid losses. The
ability of the cement slurry to transmit hydrostatic
pressure, that affects the total hydrostatic pressure
of the annular column, is a function of the cement
slurry gel strength (Gonzalo, et. al., 2005). The
higher the gel strength, the lower is the
transmissibility of the annular hydrostatic
pressure.
The length of time from the point at which the fluid
goes static until the SGS (Static Gel Strength)
2
reaches 100 lb/100 ft is referred to as the “zero
gel” time. When the (SGS) value reach 100 lb/100
2
ft it starts to loose its ability to transfer hydrostatic
pressure. When the SGS value reaches 500
2,
lb/100 ft the fluid no longer transmit hydrostatic
pressure from the fluid (or the fluid above it). The
time required for the fluid’s SGS value to increase
2
2
from 100 lb/100 ft to 500 lb/100 ft is referred to
as the “transition” time. To control gas migration,
the “zero gel” time can be long, but the “transition”
time must be as short as possible (preferably, less
than 30 minutes) (Diamond, 1983).
4
Use of Expansion
cement bond.
SPE 150751
additive
for
improved
Burnt Magnesium Oxide (MgO) can be used as
expansion additive. According to research, some
conclusions can be drawn that adding of these
additives will increase shear bond strength but will
reduce compressive strength although still higher
than recommended minimum value (Rubiandini,
2000). The value of shearbond strength and
compressive strength are reduced proportional to
the increment of burning temperature of MgO,
generally, the higher the burning the temperature,
the harder the MgO gets and the harder it is for
the MgO to react with cement.
Burning Magnesium Oxide is done to slow down
their hydration process when in contact with water.
These additives are fully hydrated after setting of
the cement, which allows them to provide
excellent expansion at curing temperature up to
o
o
550 F. This additive burnt at 1200 C is only of
o
benefit at temperatures higher than 140 F, but for
o
o
low conditioning temperature, 100 C-135 C, the
o
MgO burnt at 1000 C is reliable. Using the MgO at
temperatures below what it was specified for will
not be beneficial because the hydration will be too
slow to provide the required expansion
(Rubiandini, 2000). Hence a proper effect of the
expansion additive will be obtained if the MgO
reacts at the same time as the process of
hydration of the cement (Al-Yami et al, 2009).
Efficient Displacement of Mud
The most important factor in obtaining a good
primary cement job is properly displacing the
drilling fluid (Sudhir and Caven, 1998). If the mud
is not properly displaced, channels and or pockets
of mud may be left in the cemented annulus,
which can lead to inter-zonal communication and
casing corrosion. Assuming adequate bulk
displacement has taken place, bonding of the
cement to the pipe can be less than desirable
should said surfaces not be conducive to cement
bonding. Coatings from mud additives (polymers,
corrosion inhibitors, etc) and non-aqueous mud
systems can interfere with the bonding between
the cement sheath and the pipe surface. Such
poor bonding is typically reported as a microannulus as viewed by a cement evaluation log and
is often blamed for poor zonal isolation either via
immediate inter-zonal communication. One of the
aspects of ensuring an annular seal during a
cementing operation after achieving bulk
displacement of the drilling mud is bonding of the
cement to the formation and wellbore surfaces.
Spacers and flushes are effective displacement
aids because they separate unlike fluid such as
cement and drilling fluid, and enhance the removal
of gelled mud allowing a better cement bond.
Compatibility test of the mixture of the fluids with
the spacer must be conducted to ensure there will
be no incompatibility problems when pumped into
the well bore.
Mud removal is important in all cementing as the
interface between the cement and the formation is
affected by its effectiveness, but it is particularly
crucial in HPHT wells to achieve a good cement
placement and a good cement/formation bond. For
a mud to be displaced effectively it must;
•
•
•
Have a low plastic viscosity to yield
viscosity ratio!!!" !"
Have a minimal gel strength development
(North et al, 2000).
The design of drilling fluid and
displacement is important in cementing,
because there must not be incompatibility
issues which could cause sludge
formation and downhole problems.
Casing Design.
The casings chosen will have to be designed to
withstand the high pressure in these regions so it
is important that the casings have high MAWP to
withstand this pressure to prevent a burst due to
heavy cement being pumped through the casing
string or collapse of casings due to pore pressure.
This choice will lead to a higher grade of casing for
the well. Due to the changes in temperature and
pressures the casing is subjected to, the sheath
should be able to accommodate the changes and
not develop a facture.
Conclusion
Among others, issues such as effect of
temperature and pressure, large stresses,
degradation of set cement and strength
retrogression at elevated temperatures, small
ECD windows and poor temperature prediction are
great concerns and posses a big challenge in
HPHT wells.
The use of temperature and cementing simulators
to accurately predict downhole condition will help
in accurate slurry placement and equipment
selection. A slurry that contains silica flour to
prevent
strength
retrogression
at
high
temperature, mixture of manganese tetraoxide
(Mn3O4) and Hematite as weighting agents, latex
additives to control gas migration and magnesium
O
oxide burnt at 1200 C as expansive additives with
other conventional additives are recommended for
SPE 150751
cement slurry design for HPHT wells. Efficient
fluid design and displacement and applicaton of
Best practices are panacea for successful job
execution and excellent service delivery.
References
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