8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
1/11
Achieving full isolation between producing
zones has always been a major challengefor cement technologists. In some areas of
the Middle East this is particularly difficult
to achieve in tophole sections. In every
well, the optimization of cement slurry to
take account of the difficulties presented
by formations, borehole conditions and
wellbore fluids, and to produce a set
cement with the necessary mechanical
properties is a complex business.
Here, Jo Schultz and Andrew James
outline the problems that face cementing
engineers in the field and explain how
attention to particle size and distribution
has resulted in a range of high-
performance cements.
Hard and fast the cement challenge
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
2/11
M i d d l e E a s t R e s e r v o i r R e v i e w
Figure 6.2:USI*
Ultra Sonic Imager
images showing
early casing
corrosion
The successful isolation of drilled-
through formations is extremely
important in preventing the migration of
gas and fluid and limiting their
environmental impact. It has been
estimated that around 70% of all gas
wells have some kind of zonal-isolation
problem. A good, primary cement job
could have prevented most of these
situations and the subsequent remedial
work. There has always been a conflict
for conventional oilfield cements
between optimizing slurry properties for
mixing and placement and the resulting
mechanical properties of set cement
necessary for long-term zonal isolation.
In the Middle East, zonal isolation has
been difficult to achieve in tophole
sections. This is due to a low fracture
(rock failure) pressure gradient and the
existence of highly expansive and
fractured, vugular or cavernous dolomite
formations such as the Wassila, Simsima,
Shuiaba or Umm El Radhuma sequences.
On many occasions, standard, lightweight
cement systems have failed to provide
the necessary zonal isolation because of
the complex demands placed on the
slurry. Even with the sealants and special
casing tools that have been developed for
complex situations such as these, the
entire casingformation annulus is
seldom fully isolated.
In another Middle Eastern scenario, a
promising oil source in South Oman is
providing challenges to successful, high-
density cementing operations in deep
wells with high bottomhole pressures
and a very narrow margin between
formation, pore and fracture pressures.
New technology, which focuses on the
size and distribution of particles in the
cement, has produced a lightweight
slurry system with reduced water
content that gives the set cement an
inherent high compressive strength,
along with low porosity and permeability.
This increases the systems durability by,
for example, reducing the ability of fluids
to penetrate through the casing, which,
in turn, arrests the onset of corrosion.
The same principles have been applied in
producing a range of high-density, high-
performance slurries (HDHPS).
Traditional cementing
Well cementing was introduced by
Portland Cement in 1901. This was seen
as the most readily available, economical
and simple means of filling the annulus
between pipe and formation. Fluid
density was adjusted to suit the
hydrostatic pressure involved by
changing the amount of water added
during mixing.
Cement was pumped down to the
lowest point in the well, then back up the
casingformation annulus. A common
problem was contamination of the cement
by the drilling fluid that it was displacing.
Chemicals in the drilling fluid affected
both the setting rate and the mechanical
properties of cement. To overcome this,
another fluid compatible with both the
drilling fluid and the cement was pumped
ahead of the cement. This fluid also
helped to clean the casing and the
formation prior to cementing.
Optimizing these and all the other
operational variables, such as correct
pressure maintenance, was a major
challenge. Software such as CemCADE*
cementing design and evaluation
software (Figure 6.1) was developed for
this purpose and is constantly being
updated to keep pace with new
cementing challenges and changing
slurry technologies. The main
considerations are:
Proper pressure control in the well at
all times. The total pressure exerted
by moving fluid on the formation is
maintained between the pore pressure
and the fracture pressure of the
drilled-through formations. If this
pressure becomes too low, fluid can
flow between zones and could cause a
blowout. If it becomes too high, fluid
will be lost to the formation
Figure 6.1:
CemCADE dynamic
pressure simulation
software for the
design and
evaluation of
cement jobs
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
3/11
7
Num
ber
2,20
01
M i d d l e E a s t R e s e r v o i r R e v i e w
MD, ftGR(0-100 GAP)
FMI images FMS100
porosity(pu)
Hist.0
0.50.5
00
Log eff.por.FMI por.
0 90Dips
Cavityin connectionwith fractures
Cylindrical view(dynamic images)
Horizontal well
100% mud losses are
encountered below 6770 ft.In this interval, openfractures, cavities, andsolution-enhancedfeatures are observed
Open fractures
Secondary porositydue to vugs and fractures
6782
6784
6786
6788
6792
6794
6796
Dips of openfractures
Large, open cavity causes veryhigh porosity computation
Open fractures
Secondaryporosity
Secondary
porosity
Secondary porositydue to large cavities
and open fractures
The use of additives to control the
frictional pressures caused by fluid.
These pressures will also increase
along with viscosity, elapsed time,
temperature, loss of fluid to the
formation, or combinations of these
factors. As a result they can cause
bridging in the annulus (due to
premature cement setting) with
disastrous results
Simulation of spacer and cement
placement at well conditions to ensure
optimum displacement of the mud
The design of preflushes to reduce
risks of channeling (channels of
unremoved drilling mud), which can
lead to the production of formation
fluids, gas migration to surface,
decreasing production rates, early
casing corrosion (Figure 6.2), and
microannulus (hence loss of zonal
isolation). Loss of zonal isolation results
in loss of control between one zone and
another (also known as underground
blowout). Risks are minimized by
optimizing flow regime selection,
annular flow rate, preflush contact times
and volumes and fluid designs.
Figure 6.3: FMI images
from the horizontal well
show variations in rock
appearance along the
well. Porosity analysis
from the images
computes very high
porosity across the
vugs, large, open,
solution-enlargedcavities, and fractures.
Huge mud losses were
encountered over this
interval
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
4/11
M i d d l e E a s t R e s e r v o i r R e v i e w
Cementing in low-pressure reservoirs
In low-pressure reservoirs, the challenge
is always to find an acceptable balance
between the liquid slurry properties
necessary to place the slurry
successfully and the set cement
properties once the slurry is in place.
Often in low-pressure reservoircementing, problems with well balance
between pore and fracture pressures
arise even before the cementing
operations begin. Extreme levels of water
loss from the drilling fluid, or even the
complete loss of the drilling fluid to
the formation can occur. Current
technologies cannot predict and manage
these situations during drilling. Proper
recognition and treatment of pressure
changes can dramatically minimize their
impact on primary cementing operations
and can save operators between $100,000
and $1,000,000 on the cost of a well.
FMI* Fullbore Formation MicroImager
data can help field managers to
understand the extent of the vugs and
fractures (Figures 6.3 and 6.4) and the
mechanism of losses, and possibly help
them to combat these losses with
efficient solutions. Drilling fluid losses
cause operational delays. Drillpipe must
be removed to allow changes to pipe
geometry for expensive and time-
consuming circulation loss treatment.
InstanSEAL* is a newly developed
loss circulation treatment that can be
pumped through the drill bit without
interruption to the normal drilling
operation. It has recently helped several
companies to reduce the severity of
drilling fluid losses (Figure 6.5) to a
manageable level, and allowed the
continuation of the drilling operation.
The injection of a single fluid pumped
through the bottomhole assembly
(BHA) directly in front of the loss zone
and sheared at the bit nozzles, rapidly
generates a high-viscosity gel. This
gelling mechanism ensures accurate
placement of the treatment at the loss
zones, and has a higher success ratio
than treatments that require downhole
temperature or fluid interaction.
Reaction time for the change of the fluid
(from a few seconds to an hour) is
controlled by adjusting the activator
concentration to match the planned
Figure 6.4: FMI images from the vertical well showing an abrupt change in
porosity type in the interval 45754620 ft. Huge mud losses were encountered
in this interval due to a well-connected system of vugs and solution-enhanced,
open cavities as shown by the images. Very high porosity is computed for such
features due to their open nature.
MD, ftGR(0100 GAPI)
FMI dynamic images
50
FMI porosity histogram
(pu) 0
0.50.5
00
Log effective porosityFMI porosity
4570
4580
4590
4600
4610
4620
4630
4594
4596
Verticalscale1/100
Verticalscale1/100
Solution-enhanced cavity
High FMI porosity due to vugs, largecavities and solution-enhanced fractures
Secondary porosity
fluid pump rates. After placement, the
gel is stable for several weeks under
downhole conditions, and provides
enough time to drill and complete the
section. The BHA can be pulled through
the set gel. However, in cases where the
asset team are trying to avoid damage to
a producing zone, the gel can be broken
with a weak acid.
Another method used to prevent
losses during cementing uses special
ported tools, known as stage collars, in
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
5/11
7
Num
ber
2,20
01
M i d d l e E a s t R e s e r v o i r R e v i e w
CG62P70 x80 100microns
Figure 6.6: 35% foam-quality cement (top)
62% foam-quality cement (bottom)
0
Well 1 Well 2 Well 3 Well 4
200
400
600
800
1000
Losses,
bbl/hr
BeforeAfter
Figure 6.5: These case histories show that drilling fluid losses
decrease dramatically after an InstanSEAL pill is pumped downhole
lightweight slurry system based on
CemCRETE* concrete-based oilwell
cementing technology. This new system
gives high compressive strength along
with very low porosity and permeability of
the set cement for longer durability and
reduced casing corrosion.
Traditional cementing:low-density, low-strength
The traditional optimum water-to-
cement ratio is 44% (unaltered Portland
API class G cement mixed at a density of
15.8 lbm/gal). This has moderate
viscosity and acceptable levels of
separation of free water from the slurry
when settling. The set cement has a
permeability to gas of about 0.1 md. Its
compressive strength is more than
sufficient, and, under normal
circumstances, it is used as the anchor
or tail-in slurry for casing strings.
The following are some of the options for
reducing the cement density:
Adding more water. Adding too much
water upsets the settling properties of
the slurry and therefore collodial clays
or polymers are needed to maintain
stability. In addition, the set
properties of the cement are affected.
Compressive strength decreases with
increasing liquid-to-solid ratio, and
the porosity and permeability of the
set cement increase. Any reduced-
density system needing less water will
have clear operational advantages
Lightweight additives. The cement
content of the dry powder is partly
replaced with a lightweight aggregatesuch as diatomaceous earth, fly ash or
hollow aluminosilicate or glass
spheres. With this method, the
stability of the system decreases
rapidly below the 11.5lbm/gal mark as
the lightweight material becomes the
major component of the powder blend
Foaming with gas. Gases such as
nitrogen or compressed air are used
to generate foam with the normal-
density cement slurry. The
permeability remains relatively low
until a ratio of gas-to-cement slurry
greater than 35% is reached. Above
this ratio (referred to as foam
quality), the permeability increases
rapidly and the compressive strength
falls. A 62% foamed cement exhibits
interconnected bubbles contributing
to high porosity and early corrosion
attack (Figure 6.6).
the casing string that allow the
cementing of casing to be done in
several stages. As a result of this phased
cementing, the lower formations are
never exposed to the full weight of the
cement. The ports of the stage collars
are closed after the cement has been
pumped. The more sophisticated stage
collars have inflatable seals or packers
just below the opening ports. Theseisolate the pressure of the annular fluid
above the ports completely from the
weak lower formations.
Unfortunately, even with such
elaborate devices, successful isolation of
the casingformation annulus is rarely, if
ever, complete. To eliminate the stage
collar and perform the cement job in
a single stage would require very
low-density slurries to reduce the
hydrostatic pressure of the fluid column
and prevent lost circulation or formation
breakdown. Also, the ultralightweight
slurry must not only perform during the
placement stage but also after the
cement has set. It must isolate the
casing from formation fluids and prevent
the movement of fluids from one
formation type to another.
This has been made possible by the
introduction of a reduced-water,
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
6/11
M i d d l e E a s t R e s e r v o i r R e v i e w
Packed particles equalperformance plus
Recent advances in cementing technology
have focused on the way particles fit
together and the principle of solids
fraction, as used in the construction
industry. These are the key factors in
optimizing set cement performance. The
fraction of a volume of a blend that is
actually occupied by solids (i.e., particles)
is known as the packing volume fraction
(PVF). When all the particles are identical
spheres in a perfect, hexagonal, closest
configuration, the PVF is 0.74. Randomly
packed spheres, however, exhibit a PVF of
0.64 due to the decreased efficiency of
packing. A powder containing various
sizes of particles will have a higher PVF
since the smaller particles fill the voids
between the larger ones.
This concept has been used by
Schlumberger in the oil field to develop
the CemCRETE technology for
designing new high-performance
cement slurries. In this technology, a dry
blend is designed that has the specific
gravity to create a slurry of the required
weight. At the same time optimum
particle size distribution is used to
maximize the PVF up to 0.87.
The low-density application of this
technology, the LiteCRETE* slurry
system, has demonstrated properties
superior to any other technology for
lightweight cement design. The high-
performance, low-density LiteCRETE
mixture contains cement and a number
of particulates with narrow ranges of
particle diameter (Figure 6.7). To
achieve the desired specific gravity for
the dry blend, oilwell cement, silica flour
(for bottomhole static temperatures
exceeding 230F) and correctly sized,
lightweight particles are used in
optimum ratios.
The high-performance, lightweight
cements of the CemCRETE family
display remarkable slurry and set
properties. The development of early
compressive strength is very fast, as
indicated by the relatively short time
elapsed between 50psi and 500psi of all
CemCRETE-based slurries. As a result,
waiting on cement time during drilling
operations is considerably reduced. The
24-hr compressive strengths are also
very high compared with other
lightweight, conventional cement
systems. The latest developments allow
slurries to match the densities of drilling
fluids. A 8.0-lbm/gal slurry with a water-
to-solid ratio of 42% will develop a 24-hr
compressive strength of 1300psi,
whereas a 8.9-lbm/gal slurry reaches a
compressive strength of 2733psi
in 24 hr.
An additional benefit of the high-
solids fraction of CemCRETE
technology, is the permeability of the set
cement when compared to a
conventional 15.8-lbm/gal system.
LiteCRETE, even at 11lbm/gal, displays
permeabilities 10 times lower than
conventional set cement and effective
porosity is around 22%, compared to
34% for the conventional neat system.
Drilling 121/4-in. holeTwo-stage cementconventional slurry
One-stage cementlightweight slurry
Hyd. press.At zone 'A'= 0.62 psi/ftAt zone 'C'= 0.65 psi/ft
Hyd. press.At zone 'A'= 0.56 psi/ftAt zone 'C'= 0.58 psi/ft
Mud weight10.5ppg
(79 pcf)
133/8 -in. casingat 5880ft
10.5 ppg(79 pcf)
12.7 ppg
15.8 ppg16.7 ppg
15.8 ppg16.7 ppg
Lightweight11 ppg(82 pcf)
Hyd. press.At zone 'A'= 0.55psi/ftAt zone 'C'= 0.55psi/ft
Figure 6.8: Previous
and most recent
technology for
cementing 95/8-in.
casing string interval
Figure 6.7:
LiteCRETE particles
fill maximum pore
space
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
7/11
Cement medium particles
Fine particles
Coarse particles
7
Num
ber
2,20
01
M i d d l e E a s t R e s e r v o i r R e v i e w
Answers for Abu Dhabi
Cementing 95/8-in. casing in land wells in
Abu Dhabi presents unique challenges.
High hydrostatic pressure is required to
control the shale sections, and there is a
high pressure contrast between different
reservoir units. Under these conditions,
considerable losses into depleted aquifer
zones have been experienced. Losses
during cementation, poor performance of
the stage collar tool and poor mechanical
properties of the set cement resulted in
unsatisfactory primary cementing. These
challenges had previously been addressed
by cementing in two stages. A comparison
between the previous and the most recent
technology is shown in Figure 6.8.
In more than 50 successful cases for
this customer, improved casing
protection and mechanical properties
have been achieved with LiteCRETE
systems. A 95/8-in. casing is set just
above the reservoir, a few feet below
Nahr Umr shales at 80008500ft and at
85009000ft to cover the Shuiaba
reservoir pay zone. In special cases,
LiteCRETE is also used for loss
circulation plugs during drilling. A
typical USI tool/variable density log is
shown in Figure 6.9.
400 (US)
Transit time (sliding gate)(TTSL)
200 0 (mV)
CBL amplitude (CBL)
100200 (US)
Amplitude
1200
Max.
VDL variable density(VDL)
Min.
Min. ofamplitude(AWMN)
Externalradius
average(ERAV)
(in.)5 4
Externalradius
average(ERAV)
(in.)4
0.08000.00400.0800
0.25002.00004.0000
0.30003.10914.0000
5
Min. ofthickness
(THMN)(in.)
0.1 0.6(DB)0 75
0 (mV)
CBL amplitude (sliding gate)(CBSL)
100
0
Tension(TENS)
(lbf)
8100
8200
1000
-20
CCL(CCLU)(----)
20
0 (GAPI)
Gamma ray (GR)
70
400 (US)
Transit time (TT)
200
Internalradii
minusave.
(IRBK)(----)
Rawacousticimped.(AIBK)(----)
Bonded Cement map withimpedance
classification(Al_MICRO_
DEBONDING_IMAGE)
(----)
Figure 6.10: Coarse, medium and fine
particle distribution in HDHPS blend matrix
Figure 6.9: A typical USIT/VDL log
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
8/11
M i d d l e E a s t R e s e r v o i r R e v i e w
These systems are applied at one of
two surface densities: 10.0l b m / g a l
(75pcf) and 10.5 l bm / ga l (79pcf).
The downhole density increases due to
compaction of the lightweight particles
under the weight of wellbore fluids,
resulting in 10.5 l b m / g a l (79 pcf) and
11.2l b m / g a l (84 pcf) respectively.
High-density, high-performance slurries
High-density, high-performance
(HDHPS) technology optimizes slurry
placement performance and ensures a
high-quality set cement. It allows
slurries with densities up to 24 lbm/gal
(2900 kg/m3) to be used to cement
critical casing strings in wells with high
pressure gradients.
Using particle size distribution (PSD)
optimization, particles of at least three
different sizes are selected (Figure 6.10).
Adjusting the PSD allows engineers to
introduce more solids per unit volume
than would be possible with a
conventional cement slurry. The
compressive strength of the set cement
is increased, and the porosity and
permeability are lowered due to the
higher PVF that is achieved, regardless
of the slurry density. HDHPS technology
usually requires lower concentrations of
most chemical additives than
conventional technology.
As with low-density applications, the
smaller particles in the blend act like
ball bearings in providing extra lubricity.
HDHPS blends are more stable during
transportation than conventional
hematite blends, and less susceptible to
segregation of the various particles.
Testing has shown that the major
advantages of HDHPS are:
High-density slurry designs (up to
24 lbm/gal) are possible with
controllable and adjustable rheology
More field-tolerant, less sensitive to
possible density fluctuations and
more stable
Density adjustment of 0.5lbm/gal is
possible using the same blend. This
provides system flexibility for of last-
minute changes in mud weight.
More tolerant to mud contamination
Higher early compressive strength
development
Uniform and faster setting over a
range of temperatures prevents well
instability and kicks
Higher final compressive strength
Lower bulk shrinkage
Lower permeability and porosity
South Oman case study
In the southern Oman oil fields, operators
are exploring the production potential of
oil and gas from high-pressure carbonate
stringers embedded in salt. The
cementing operations face a range of
challenges, including depths of
3,5004,800m, temperatures of 95125C
and bottomhole pressures of 13,000psi.
The high densities required of the
cement slurries were achieved initially
using hematite as the weighting agent.
This gives a low Bingham-yield-point
slurry that is easily placed. The lower
water content reduces sedimentation,
the superior mechanical properties
develop more quickly and waiting on
cement time is significantly reduced
(see Figure 6.11).
HDHPS does not need specialized
equipment or personnel and the slurries
are more tolerant to mixing errors or
density variations. The dry blends may be
mixed with fresh, sea or salt water.
Optimized suspensions can include
conventional defoamers, accelerators,
dispersants, retarders, fluid loss and
control additives, and latex additives to
control gas migration.
20
18
16
14
12
10
8
6
4
2
0
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
Transittime,
sec/in.
Compressivestrength,
psi
177
159.3
141.6
123.9
106.2
88.5
70.8
53.1
35.4
17.7
0
Temperature,
C
0:00 1:45 3:30 5:15 7:00 8:45 10:30 12:15 14:00 15:45 17:30 19:15 21:00
Time (HH:MM)
UCA initial: 50 at 4:37UCA strength 1500 at 5:20
UCA strength 4280 at 20:04Comments: HDHPS at 19.5 ppg and 90C
Figure 6.12:Graphical comparison of conventional slurry and HDHPS in
terms of waiting on cement time and cement contamination for plugs
0
50
250
300
350
400
200
150
100
HDHPS plugs,wells 47
Conventional plugs,wells 13
Time,h
r
WOC time, hr
Actual TOC belowtheoretical TOC
1 2 3 3 4 4
Well
5 6 6 7 7
Figure 6.11:Compressive strength development for HDHPS
slurry measured at 90C
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
9/11
7
Num
ber
2,20
01
M i d d l e E a s t R e s e r v o i r R e v i e w
Physical and chemical robustness. The
salt-saturated mud necessarily used
affects the cement slurry and the set-
cement properties. In the past, this
has resulted in a large column of
contaminated slurry, making it
necessary to repeat some plugs. Other
problems arose due to microannulus
caused by bulk shrinkage on setting
that compromised zonal isolation.
In addition to transportation and
handling problems, placement and set-
cement mechanical properties were
below expectations. This led to a number
of problems, including loss of
homogeneity in the blend during
transportation caused by the hematite
separating from the blend. A well kicked
14 hr after cementing, causing the loss of
four days in controlling the well. In
addition, engineers had to deal with a
build-up of annulus pressure. This was
possibly due to microannulus caused by
bulk shrinkage after cement setting, or to
improper mud displacement. Downhole
contamination led to increased setting
time and four plugs had to be repeated
after setting lower than planned.
Intrasalt stringers set
challengesIn conventional, high-density cement
slurries, chemical additives, the amounts
and types of solid, water volume,
temperature and pressure all affect
performance. Although chemical
additives are helpful up to a point,
cement performance at high densities is
largely a function of density.
Density can be increased by reducing
the water content of the blend or by
adding weighting materials. Both options
have their drawbacks. Water reduction
beyond a certain level causes the slurry
to become unpumpable or unmixable.
Adding weighting materials such as
barite, hematite or ilmenite begins to
cause problems with segregation and
separation. The cementing operations
face a range of challenges.
HDHPS technology was seen as the
way forward for addressing the major
challenges that engineers face in liner
and plug cementing for these wells:
Enhanced isolation requirement. 100%
zonal isolation is essential for testing
and for separate production from
adjacent stringers
Placement pressure restrictions. The
pressure window between the
formation pore and fracture pressures
is small. This results in a small density
differential between the salt-saturated
mud system, the spacer and the
cement slurry. The cement-slurry
rheology must be low enough for
successful placement and, at the same
time, sufficient to suspend the
weighting agents
Properties Conventional slurry HDHPS slurry
Density, lbm/gal 19.5 19.5
PV, cP 126 110
TY, lb/100ft2 20 8.5
Gels 1min/10min 14/125 9/65
Fluid loss API cm3/30 min 204 64
8-hr compressive strength, psi 0 2698
Initial set 50 psi After 18hr 29 min After 5hr 44 mins
24-hr compressive strength, psi 1750 3700
Stability of set cement (BP settling test) 0.30lbm/gal top to bottom 0.15lbm/gal top to bottom
24-hr compressive strength, psi 1750 3700
Bulk shrinkage 1.5% after 24hr 0% after 24hr
Separation of heavy particles fromblend during transport
High risk Very low risk
Tolerance to density variation Low High
Table 1: Comparison of properties of HDHPS and conventional slurry for liner applications
Job date BHCT, C Well name
1 Feb 98 38 Yard trial
20 May 98 90 Well-122 May 98 90 Well-1
25 May 98 80 Well-1
20 Sep 98 90 Well-2
23 Sep 98 85 Well-2
15 Jan 99 90 Well-3
24 Jan 99 90 Well-3
28 Apr 99 90 Well-4
Job type
HDHPS
PlugPlug
7-in. liner
Plug
Plug
7-in. liner
4-in. liner
7-in. liner
Depth, m
No
43004100
3850
4713
3533
4520
4674
4418
HDHPS density, lbm/gal
19.5
21.621.6
19.5
22.1
22.1
19.1
19.1
19.5
Table 2: HDHPS jobs done to date in South Oman
Wells Cement type, hr WOC time, hr
Well-1 Conventional 45
Well-2 Conventional 101
Well-3 Conventional 40
Well-3 Conventional 120
Well-4 Conventional 79
Well-4 Conventional
HDHPS
HDHPS
HDHPS
HDHPS
71
40
37
34
26
Well-5
Well-6
Well-6
Well-7
Well-7
Conventional
Actual top of cement vs plannedbelow tested depth, m
54
206
330
120
344
84
105
124
135
106
50
130
Good cement
Yes
No
Yes
No
No
Yes
Yes
Yes
Yes
Yes
No
Table 3: Comparing results of HDHPS and conventional slurry in terms of waiting on cementtime and cement contamination for plugs
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
10/11
Application for Oman
Before HDHPS was introduced in Oman,
comprehensive tests were conducted at
several research centers in Oman and
overseas. The tests confirmed that
HDHPS would surpass the critical
performance requirements for wells in
southern Oman. In addition to exceeding
the performance of conventional cements
in 8- and 24-hour compressive strength,
stability and shrinkage tests, HDHPS
cement offered superior optimization of
slurry rheology and density (Table 1).
A trial in early 1998 demonstrated that
the HDHPS blend would not segregate
during transport but would remain
mixable after transport and easily meet the
relevant design criteria for rheology,
compressive strength and fluid loss.
Compressive strength development for
HDHPS and conventional slurry was
M i d d l e E a s t R e s e r v o i r R e v i e w
4000
3950
4050
4100
4150
4200
4250
Tension
(TENS)(lbf)
(MW)Variable density (VDL)
(US)
Min. Amplitude Max.
200 12000 50
Gamma ray (GR)
0 100 20004000
Transit time (TT)
(US)400 200
Transit time (sliding gate) (TTSL)(US)400 200
Casing collar locator (CCL)(----)-19 1
Casing collarfrom (CCL) to T1
Fluid-compensated CBL amplitude
(CBLF)
(GAPI)
Figure 6.13: Cement
bond log (CBL) forreservoir section
showing excellent
bond
measured at various temperatures. Figure
6.12 shows the performance at 90C.
The first HDHPS cementing operation
in Oman was performed in the second
quarter of 1998. Cement plugs were set
at 4,100 m (13,451 ft) and 4,300m
(14,108ft) with 21.5lbm/gal slurry. A
7-in. liner was set at 3,850m (12,631 ft)
with 19.5-lbm/gal slurry. There was a
fault around total depth, and mud losses
were encountered. The operator
decided to set cement plugs across the
fault and then cement the liner using
HDHPS for both operations.
To date, eight HDHPS jobs have been
performed for this operator, including
four liner cementing jobs and four plug
jobs (Table 2).
The average waiting on cement (WOC)
time for conventional cement before it
could be tagged was at least 72hr. The
average WOC for an HDHPS system was
34 hr. HDHPS slurries were found to be
less susceptible to contamination with
mud. Table 3 and Figure 6.12 show the
comparison between HDHPS and
conventional slurries on WOC times and
actual top of cement (TOC) tagged as
compared to the planned TOC. The top
of the HDHPS plugs tagged is closer to
the theoretical top than that of
conventional cement plugs. HDHPS
rheology can be optimized relatively
easily, which allows for more efficient
displacement of drilling fluids.
Uniformity of the blend was not
reduced by transportation to the rig site.
Mixing was smooth and without
problems. Figures 6.13 and 6.14 show the
CBL/VDL and CET log respectively for
the cement jobs on the most recent wells.
Excellent bonding was achieved over the
full cemented section.
8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001
11/11
8
Num
ber
2,20
01
M i d d l e E a s t R e s e r v o i r R e v i e w
HDHPS is worth its weight
HDHPS has eliminated a large number of
the difficulties experienced previously in
South Oman.
Compressive strength is developed
much more rapidly. This saves rig time
by allowing drilling operations to
resume sooner. Faster build-up of
mechanical properties also reduces
the risk of fluid influx from the
formation during setting
The reliability of the technology
decreases the need for remedial block
squeezes or repetition of plugs
Lower porosity and permeability of set
cements using this technology will
increase the safe life of the wells by
providing isolation of aquifers from
hydrocarbon zones and also safer
abandonment of well
Low-permeability cements are more
resistant to corrosive brines and there
is less bulk shrinkage as the cement
sets, resulting in superior isolation
through time.
According to the operators, the
success of the HDHPS technology used
so far in the eight jobs in South Oman
has ensured that it will be the preferred
system for critical cementation in all
future high-pressure wells to be drilled
in the region.
4000
3950
4050
4100
4150
4200
4250
Gamma ray (GR)
(GAPI)0 100
Relative bearing (RB)(Deg.)0 360
Eccentering (ECCE)
(MM)0 10
WW (WW)
(----)0 2
CCLU (CCLU)
(----)-0.95 0.05
CSMN (CSMX)(psi)
(psi)
AR_CSMNfrom CSMN to
RHT2
5000 0
CSMN (CSMN)
5000 0
ARF1
Between REF1 and FFLG1
ARF2
Between REF2 and FFLG2
ARF3Between REF3 and FFLG3
ARF4
Between REF4 and FFLG4
ARF5
Between REF5 and FFLG5
ARF6
Between REF6 and FFLG6
ARF7
Between REF7 and FFLG7
ARF8
Between REF8 and FFLG8
Tension(lbf)
20004000
Figure 6.14:CET logfor a recent well
Top Related