Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001

8/11/2019 Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001

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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


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


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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


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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


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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,


6/11


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


7/11

Cement medium particles

Fine particles

Coarse particles

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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


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


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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


Stability of set cement (BP settling test) 0.30lbm/gal top to bottom 0.15lbm/gal top to bottom


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-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


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


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.


11/11

8

Num

ber

2,20

01


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


ARF3Between REF3 and FFLG3

ARF4


ARF5


ARF6


ARF7


ARF8


Tension(lbf)

20004000

Figure 6.14:CET logfor a recent well

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Hard and Fast- The Cement Challenge_MiddleEast Reservoir Review, 2001

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