the effect of temperature final copy

7/27/2019 The Effect of Temperature Final Copy

http://slidepdf.com/reader/full/the-effect-of-temperature-final-copy 1/11

The Temperatures’ effect; In HPHT wells, the thickening time of the slurry is highly

reduced when temperature is high, making the cement set faster than in average temperature

wells. The rheological properties of the cement slurry is affected by temperature .When the

temperature increased the plastic viscosity (PV) and yield viscosity (YV) is decreased.

. Due to the 5oC temperature change resulting in cements thickening time , the accurate

prediction of BHCT is very crucial

There are two temperatures of importance in the well and they are:

Bottomhole Circulating Temperature; the thickening time is affected by the temperature the

slurry confronts as it is being pumped into the well.

Bottomhole Static Temperature; this temperature of the formation and it is the temperature

the slurry will be exposed to after circulation has stopped for a period of time.

The Pressure’s Effect; Pressure also has an effects on the design of the well, cement

slurry and the drilling fluid. In certain instances the pressure is not estimated properly leading to

the collapse in the casing of the well because it is inability to withstand the pressure from the

pressure of the formation and therefore a kick occurs. To create the minimum overbalance

weighting agents are used. They also reduce the pump ability of the cement thus accelerating the

development of premature compressive strength.

Small Equivalent Circulating Density Window; Simultaneously, the depth of the well and the

hydrostatic head increases resulting in an increase in ECD due to both the compression andincrease in temperature there is a decrease in ECD because of thermal expansion .

3.4.3 Remedy

a. Accurate estimation of temperature and monitoring of downhole conditions

To estimate bottom hole circulating and static temperature, computer based temperature

simulators are now being used. The simulators are run in the casing with the slurry and it

measures the immediate temperature as the slurry moves from surface to bottomhole. A

computer software program which is the cement simulator calculates and shows all job

parameters, such as flow behavior, Flow rate/ annular velocity and differential pressure. It

predicts 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.

To optimize the cementing operation, the software is used by recommending the best

displacement rate and density of slurry (based on ECD behavior between fracture and pore

density line) the simulator ensures that during the cementing job the downhole pressure doesnt

exceed the fracturing pressure of the formation or drop below the pore pressure.

b. Ef fi cient Design of Slur ry.

Cementing of a HPHT well successfully, major consideration should be given to design

of slurry and slurry placement techniques. Certain characteristics of a particular well state the

slurry assets and performance. The slurry should develop the required aspects and separate the

zones, as well as protect the exterior.

For cementing deep wells, the procedures are basically the same. As those for shallower

wells; nevertheless, such wells are generally considered serious, because of the more severe well

conditions and higher complexity of the casing programs. A three step 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

testing, and cement slurry placement and monitoring

. Consequently, the cement system design can be complex, involving an elaborate array of

retarders, fluid-loss additives, dispersants, silica, and weighting materials.

c. Cement Systems Stabil ization and Strength Retrogression Stopping

Strength retrogression, an occurrence that occurs naturally with all Portland cements at

temperatures of 230 to 248°F (110 to 120°C), is regularly escorted by a loss in impermeability,

and caused by the construction of large crystals of alpha-dicalcium silicate hydrate. Commonly

used to prevent strength retrogression by modifying the hydration chemistry is is silica flour or

silica sand and it can be used with all classes of Portland cement. The addition of 30 to 40%

silica is usually sufficient to create a set cement with low permeability (<0.1millidarcy) that



overcomes the problems of strength retrogression, though additions can range from 30 to 100%.

Silica causes the reaction with cement and water to produce xonotlite at high temperatures

instead of tobermorite. Xonotlite is stronger and results in a significantly smaller increase in

permeability

d. Slurry design for HPHT wells by Antigas Migration

25% of the primary cement jobs failures is caused by gas migration. The annular cement

provides an effective zonal isolation for the life of the well in order that oil and gas can be

produced safely and economically and that’s its major purpose. Of the main problems for

achieving this aim is the migration of fluid in the annular space after well cementing. The main

factor thwarting the fluid from entering the cement is cement hydrostatic pressure 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. It must not exceed fracturing pressure of the

formation to avoid losses. The ability of the cement slurry to spread hydrostatic pressure

affecting the total hydrostatic pressure of the annular column, is a function of the cement slurry

gel strength. The higher the gel strength, the lower is the transmissibility of the annular

hydrostatic pressure.

From the point at which the fluid goes static until the SGS (Static Gel Strength) reaches

100 lb/100 ft2

, that length of time is referred to as the “zero gel” time. When the (SGS) value

reaches 100 lb/100 ft2

it starts to lose its ability to transport hydrostatic pressure. When the SGS

value reaches 500 lb/100 ft2, the fluid no longer transmits hydrostatic pressure from the fluid (or

the fluid above it). From 100 lb/100 ft2

to 500 lb/100 ft2

, the required time for the SGS fluid’s

value to increase, is referred to as the “transition” time. In attempt to control gas migration, the

“zero gel” time can be long, but the “transition” time must be as short as possible.

e. Using Expansion additive for improved cement bond.

Used as an expansion additive; Burnt Magnesium Oxide (MgO). Conclusion can be

drawn that the addition of additives as such increases shear bond strength but reduces

compressive strength even though it might be still higher than the recommended minimum value,

according to studies. The value of shear bond 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.

Done to slow down their hydration process when in contact with water is the burning of

Magnesium Oxide. These additives are fully hydrated after setting of the cement, which allows

them to supply exceptional extension at curing temperature up to 550oF. This additive burnt at

1200oC is only of benefit at temperatures higher than 140

oF, but for low conditioning

temperature, 100oC-135

oC, the MgO burnt at 1000

oC is reliable. Using the MgO at

temperatures below what it was specified for will not be helpful because the hydration will be

too slow to offer the required expansion. Thus, if the MgO reacts at the same time as the process

of hydration of the cement, an appropriate effect of the expansion additive will be obtained.

f . Ef fi cient M ud Di splacement

Properly displacing the drilling fluid is the most vital factor in obtaining a good primary

cement job is. Channels and/or pockets of mud may be left in the cemented annulus if the mud is

not correctly displaced, which can lead to inter-zonal communication and casing decay.

Assuming sufficient bulk displacement has taken place, bonding of the cement to the pipe can be

less than wanted should said surfaces not be beneficial to cement bonding. Coatings from mud

additives (polymers, corrosion inhibitors, etc) and non-aqueous mud systems can hinder the

bonding between the cement sheath and the pipe surface. Poor bonding as such 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. Bonding of the cement to the

formation and wellbore surfaces is one of the features of ensuring an annular seal during a

cementing operation after achieving bulk displacement of the drilling mud.

Effective displacement aids are Spacers and flushes because they separate unlike fluid

such as cement and drilling fluid, and boost the removal of gelled mud allowing a better cement

bond. Compatibility test of the fluids mixture with the spacer must be performed to ensure there

will be no incompatibility problems when pumped into the well bore.

4.1.1 Flow of Salt Formation

Salt sections exhibit plastic-flow characteristics under adequate temperature and pressure.

It is a known fact that a salt section tends to be more sensitive to temperature and pressure than



the adjacent formations even though it is intricate to associate the enormities required to initiate

plastic salt flow because of the diversity of environments

if they are at depths of less than 5,000 ft, at temperatures below 200°F (93°C) or less than

1,000 ft thick, salt formations are rarely plastic or problematic. The deformation can be much

less apparent in the case of salt beds. When a well is drilled through a salt section, stress within

the salt is relieved and the salt flows toward the wellbore. Salt sections should be short-tripped

and reamed on a regular basis for this reason,

A salt can flow (“creep”) suitably to close off the wellbore and stick the drillstring.

Freshwater sweeps can be used to dissolve the salt that is creeping and to release stuck pipe. A

freshwater pill of 25 to 50 bbl is usually satisfactory to free stuck pipe. Good drilling practices

can also minimize salt-deformation problems. Drilling each joint or stand and wiping over that

section prior to making the next connection will help guarantee the salt has been opened

sufficiently and has been stabilized. Also helping to ensure the hole has remained open, regular

wiper trips back through the salt to casing

escalating the mud weight is the only practical way to control the rate at which the

wellbore closes. The closure may never be eradicate, but it can be controlled to an acceptable

level during the interval of time it takes to drill the section. The force extruding the salt is equal

to the weight of overburden. This means that mud weights can be very high.

Generally speaking, the higher the mud weight, the greater the depth of burial. Mud

weights required for drilling salts can be excessive as in 20.0 lb/gal (2.4 SG). The mud weight

required to reduce salt creep to less than 0.1% per hour can be anticipated from the formation

temperature and depth.

In the case of a completed well, salt can flow satisfactorily to collapse casing. In some cases, the

movement of the salt is so slow, it takes years before this problem is apparent. High-strength

casing and a good cement job after drilling a nearly gauge wellbore tend to distribute the salt

loading more evenly over the interval, thereby reducing the potential for casing collapse.

Experience has shown that it is a good practice to use a high-compressive-strength, salt-

saturated-resistant cement and high-strength casing designed for 1.0 psi/ft collapse.



4.1.2 Solubility

To begin with we have to define what solubility is. It’s when formations of

salt dissolve. rock salts are composed of homogenous and heterogeneous minerals , the

homogeneous form 99% halite. Rock salts are composed also of alkaline metals and alkaline

earth metals. Some examples of those are Na , Fe , Ca, which are named generically as halite and

anhydrite.

This property is the result of fluid dynamics and chemical outcome on salt formations which lead

to the dissolution of rock salt. Formations of salt dissolve in water by various salt formations

have relative different in their solubility in water due to their varying compositions.

experiments in laboratories show that halite salts confirm that NaCl is ionic and soluble in polar

liquids such as water. It is not soluble in non-polar liquids like alcohol .solubility in water islimited by the salt content of the water. therefore ,the diameters of wellbore can be enlarged due

to salt dissolution and mud flushing.

The solubility of salt creations is the property that controls the connections of the formation with

fluids such as penetrating fluid (mud) and cements. Drilling fluids is chosen on predicted

responses with salt formation. The expected flow system donates to the choice of drilling fluids.

Samples of salt are tested on solubility property.

4.1.3 porosity and permeability :

These are the essence features of geologic materials. They are major features that control

the storage and movement of fluids in rocks. Porosity is the ratio of the volume of voids to the

total volume of material. Porosity is the storage capacity of the geologic material. Permeability is

a measure of the affluence with which fluids will flow though a spongy rock medium. Virgin

rock salt is usually depict by very low porosity (<0.5, - 1.0%) which in some cases may be less

than 0.1% a part of of pore volume takes place as closed voids of gas, and brine.

In order to measure salt formations we use the value 10-20 m squared. It shows that we can

use these rocks in storing gases and wastes. Porosity and permeability of salt formations result in

slink behavior. We face a problem in measuring porosity and permeability , that problem is the

solubility of rocks salt in the liquids.



4.1.4 Formation (Pore) and Fracture Pressures:

What is pore pressure? It’s the pressure performed on fluids inside the pores of rocks. Pore pressure can be normal, abnormal,or subnormal. Abnormal formation of pore pressures take

place when joining geochemical , geophysical and mechanical processes . Salt deposits do not

allow pore fluids to escape. Pore fluids are rapt and pressured. salt formation is its tectonic stress

diffusion during its flow or response to an applied stress. Salt formations absorb tectonic

(surrounding) stresses therefore, the overburden stress from above and transmit equal stresses in

all three directions in order to achieve stress equilibrium or isotropy. This leads to the increase of

horizontal stress to values greater than or equal to the overburden stress; thus, this instance of

stress system requires casings set across salt sections to have higher collapse strength. the

movement of salts (i.e. diapirism) into overlying sediment s creates a lateral seal which inhibits

pore water expulsion.

We must define the meaning of Fracture pressure.It is the most pressure a formation can

give before it fails or breaks. Fracture gradient is the pressure gradient (in psi/ft)or density (in

ppg) that gives a pressure equivalent to the fracture pressure. In piercing salt formations the

fracture gradients are estimated and incorporated into the mud and casing design.

Proven to be relatively higher than the surrounding non-salt formations at a comparable

depth are the fracture gradients in shallow salt formations. Because the density of salt does not

change with burial depth compared to other clastic sediments and salt transmits stresses which

contribute to the fracture pressure in the deeper non-salt formations, deep salt formations may

have moderately lower or approximate stress values with the non-salt formations at deeper

depths, though. The rather higher fracture gradients permits casing point extension and casing

strings elimination which reduces well costs and rig time, in shallow formations. Also, the mud

weight used for the shallow salt sections should be carefully selected considering the exit

formations which are likely to be relatively weak and possible zones of lost returns. Note that

casing elimination should be done only if hole troubles will not occur within the salt formation.In fundamental nature, well planners must estimate the fracture gradient of the salt

section to be drilled and the mud weight that will be required when exiting the massive salt

section. Information like this provides the basis for the casing depths within or out of the salt

formation and permits the choice of an optimum location of salt exit; formation pressure tests in

salts are frequently restricted to a greatest value of 1.0 psi/ft while some salt sections can endure



mud weights larger than this pressure gradient. Yet, formation integrity tests are rarely run to

fracture pressure; fracture in salt formations are feared because it is supposed that the fracture

will evolve to non-salt areas or that salt will trickle away due to drilling fluids moving along the

fracture path. The alternatives of salt exit depend on variation between the lowest fracture

pressure or equivalent mud weight (EMW) in the salt (at the top of the salt) and the fracture

pressure of the closest non-salt formation below the salt. The fracture EMW at the top of the salt

is 12.8ppg and the best option of salt exit is option B because the formation has a fracture EMW

of approximately 13ppg (close to 12.8ppg); hence the mud weight required to exit the should be

less than the fracture EMW of the exit zone and lower than the lowest fracture EMW within the

salt. The most complimentary extent of wellbore section in salt is LB though longer than LA.

Experience demonstrates that cement squeeze will raise the fracture EMW at the casing shoe if

there is need to set casing in the salt.

4.1.5 Other Salt Properties

From hard to (at the bottom) to soft (at the top) the layers of sediments graduated. With

interfaces the layers are separated from each such that the acquaintances are weaker between the

top and stronger layers between the bottom layers. As we drill deeper relatively to other clastic

formation; Layers of salt formation become harder and more consolidated hence, the drilling

tools must be able to withstand the abrasiveness and toughness of the formation.In salt formations friction and hardness are high and can cause several damaging issues

including severe stick-slip, poor directional control and lateral quivering. Particularly, friction-

generated torsional vibrations or stick-slip generated are very prominent in salt formations and

limits the penetration rates and hole quality. To mitigate these issues, the coefficient of friction in

a typical rock salt is 0.7 and the bit designs are steadily improving. Hardness is the measure of

the resistance of a rock to breakage and is measured on the Mohr Hardness Scale (Softest = 1,

Hardest = 10). The hardness for sodium chloride, NaCl (the chief component in halite) is

between 2.5 and 3 varies. Rock salt (halite) melts at 800oC and 1 atmosphere pressure, and at

higher temperatures and higher pressures, in terms of temperature reactions.

Geophysically, observing how the diverse types of salt cause seismic waves to act in

another way while the waves spread through the salt units is the standard for classifying

anisotropy in salt formations. Anisotropic constants are included into equations and models for



calculating the three dimensional stress and strains in salt formations; rock salt models from the

field of interest should be recovered to surface for anisotropic analysis and tests.

4.2 Drilling Fluid Solution

4.2.1 Water-Base Systems

One of two approaches is used with water-base fluids:

the use of a saturated salt system

the use of a slightly undersaturated system to encourage hole enlargement which

keeps deformation of the salt from causing stuck pipe.

Depending on the actual conditions, the undersaturated option is sometimes difficultto manage and can easily lead to excessive hole enlargement causing further

complications in obtaining a collapse-resistant, cemented casing.

4.2.1.1 Saturated-saltwater-base systems .

Water-base drilling fluids should be designed to be compatible with the salt to be drilled.

For mixed salt formations like carnalite, this can be intricate, but magnesium chloride, non-

standard oilfield salts, would be required and may not be readily available. When the salt is first

penetrated, it is vital to have the system completely saturated to prevent excessive hole

enlargement in the top of the salt. The system will stay mostly saturated while the salt is being

drilled.

In their relying mainly on polymers, not clays, to obtain good properties, these saturated

salt systems are unlike from other water-base muds. The clays will flocculate, increasing

rheology and fluid loss when prehydrated freshwater bentonite slurry is added to a saturated salt

fluid. Bentonite-generated viscosity will diminish with time after this initial flocculation.

Prehydrated bentonite is frequently valuable for sweeps and for obtaining good filter-cake value,

even if its benefit is somewhat diminished with time. Once the chlorides are greater than 10,000

mg/l. SALT GELT (attapulgite) or DUROGELT (sepiolite) can be used to provide viscosity in

saltwaters, dry bentonite will not yield. Polymers like Hydroxyethylcellulose (HEC), DUO-



VIS,T XCDT or FLO-VIST will yield to provide rheological properties. Critical for suspension

HEC will not provide low-shear-rate viscosity.

With HEC, POLY-SALE, MY-LO-JELE or FLO-TROLT starch or ultra-low, super-low

viscosity Polyanionic Cellulose (PAC) additives like POLYPACT SUPREME UL, POLYPACT

UL,2

etc, fluid-loss control can be obtained. Special-application, high-temperature-stable and

calcium/magnesium-tolerant polymers can be used for fluid- loss/rheology control under high-

temperature (>275°F or 135°C) conditions. That the performance of many polymers is reduced

in the presence of highhardness brines, particularly anionic polymers such as PACs and Partially

Hydrolyzed Poly Acrylamides (PHPA) should be noted. The shared presence of high pH (e.g.,

after drilling cement) and high hardness can also reduce the performance of xanthan viscosifying

polymers.

Some precipitates can be formed depending on the type of salt drilled which can be salt

or hydroxide compounds. The discussion of mutual solubility of salts is covered in the hole-

enlargement section. Magnesium chloride can precipitate magnesium hydroxide in a high lime or

high pH mud.

4.2.1.2 Undersaturated water-base systems.

The use of undersaturated salt systems has been perfected so that the rate of salt

dissolution is matched to the rate of salt creep in some areas. For long salt sections, the rate of

creep can vary widely from top to bottom, and the mud in the annulus may become saturated at

the bit (from salt cuttings) so that it cannot dissolve any more salt as it circulates up the annulus

which is one difficulty with this approach. This method should only be used in areas where the

salt section is short and where it is a common practice on offset wells.

4.2.2 Invert-Emulsion Systems

Also used to drill salt sections are oil- or synthetic-base muds. Salts will still dissolve into

the water phase, keeping it saturated, even though the oil wetting ability and lower water content

reduce salt dissolution and control hole enlargement. There are several reactions that can arise

due to the overload lime concentration and high chlorides which can be unpredictable and vary

depending on salt composition and temperature. These systems can be formulated with a variety



of salts in the water phase as an alternative to calcium chloride. Sodium-chloride and

magnesium-chloride internal-phase systems have been used successfully. Salts can actually be

more detrimental to invert emulsion muds than to water-base muds, although oil-base systems

are preferred for drilling salt so that a gauge hole can be preserved. The most harmful

characteristics are recrystallization of salt and magnesium hydroxide precipitation; both reactions

produce extremely fine particles with a tremendous surface area leading to a rapid depletion of

emulsifiers and oil-wetting agents. Consuming the emulsifiers and wetting agents results in

water-wetting of solids.

the effect of temperature final copy

Documents