Chapter SixChapter Six

Fluids andFluids and

CementCement

11

1.1 Drilling Fluids

 

 

 

 

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1.1.11.1.1 Introduction Introduction

1.1.1.11.1.1.1 GENERAL GENERAL

Man has been excavating the ground to recover the earth's resources since before

recorded history. The drilling industry has long been a part of this occupation. It has

come a long way since the Chinese and Egyptians first started using boring machines.

Today our industry is capable of

drilling to over 20 km depths

drilling 10m diameter shafts

drilling 2 km horizontally at 3 km depth, and turning at right angles.

extracting geothermal energy at 400°C

drilling in 5 km water depths

drilling square holes

Truly remarkable feats. One of the controlling factors in this development has been the

corresponding strides made in drilling fluid technology. Today we can formulate fluids

to:

withstand over 200°C

transport pipeline debris over 192 km

carry 5kg pieces of metal vertically from depths over 1,000m

transport gold ore vertically from 4,000m

but regrettably there is often a large discrepancy between what we can have and what we

often use.

The name 'Mud Doctor' has been used for many years as a humorous title for the drilling

fluids engineer. Although quite funny, it is not that far from the truth for the drilling fluid

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can be viewed as the life blood of the drilling operation. It cleanses the system, delivers

energy and carries "antibodies" to combat system problems. Without it drilling cannot

operate at peak performance.

The drilling fluid engineer's role is to ensure that the drilling operation remains fit and

healthy. To do this effectively he must be knowledgeable of the anatomy of the body

(formation and well) and diagnose for genetic defects (downhole problems) and the blood

disorders (contaminants). He must then specify remedial treatments to ensure the correct

physico-chemical balance is maintained to maximise performance.

However, in some respects, the name has also developed somewhat from "Witch Doctor".

The mud industry has historically been secretive about how to plan and run a drilling

fluid. Expressions such as 'experience', 'in-house expertise' and 'trade secrets' have often

been bandied about to limit the spread of knowledge. Sometimes it can almost appear to

be "Black Magic", with the old Mud Doctor throwing in a secret ingredient or two and

getting dramatic effects. This secrecy has often blinded the drilling fluids industry to the

needs of their customers if the latter don't know how it is done they may not want to

challenge what is recommended for fear of appearing ignorant.

One reason given for this restriction of information has been the protection of R&D and

training investment. "No company can afford to give away its technical and commercial

advantage". Equally we cannot afford to have inefficient and expensive drilling fluids;

that compromises our technical and commercial advantage. The ultimate goal, for all, is

the well being of our operations. The responsibility for resolving any potential conflict

lies with both sides. Understanding and properly using drilling fluids does produce

successful wells, ignorance can, and often does, have the opposite effect.

1.1.1.21.1.1.2 THE ANATOMY OF A DRILLING FLUID THE ANATOMY OF A DRILLING FLUID

What is the difference between Mud and a Drilling Fluid? Mud is a mixture of dirt and

water whereas a Drilling Fluid can be:

a Tool to Maximise Results and Minimise Costs

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What are the Functions of a Drilling Fluid? Classically these have been listed as being to:

deliver sufficient energy to the bit to assist drilling.

clean the drilling face of newly made cuttings.

cool, clean and lubricate the bit.

drive any downhole motor or turbine.

transport the cuttings out of the hole.

suspend the cuttings during periods without circulation.

stabilise the sides of the borehole.

maintain an impermeable barrier on the borehole wall opposite porous and

permeable formations

provide hydrostatic head to avoid the influx of formation fluids into the borehole.

release the carried cuttings before recirculating into the hole.

to transmit data to surface.

This list of functions does not however accurately portray the true role of the fluid in the

drilling operation nor does it indicate the potential impact upon the business. Like a

doctor, or scientist, the fluids engineer needs all of the facts and must evaluate the whole

picture before formulating an effective solution.

Putting the key functions from above into context against where in the system they are

required, as illustrated in Figure 6.1.1, a clearer picture starts to emerge, not only of what

the fluid is supposed to do, but where, how and under what conditions.

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Figure 6.1.1: Functions of a drilling fluid

By analysing the functions of the drilling fluid in the context of the operation we can

build up a better understanding of the way it must perform, and under what influencing

conditions. Thus we are able to prescribe the optimum specification for the job to be

done, monitor the performance and carry out remedial treatments to rectify any short

fallings.

1.1.1.31.1.1.3 DRILLING FLUID PLANNING DRILLING FLUID PLANNING

All of a drilling fluid's functions are important, however the specific goals of a particular

drilling operation will place different emphasis on them; for example, drilling through a

water sensitive shale will place more emphasis on the borehole stability aspect than

would drilling through a competent limestone. The key to efficient drilling fluid design,

and well planning, is using a logical, structured approach to programming. Such an

approach encompasses:

specifying and ranking the goals and expectations of the operation.

recognising the system requirements to achieve the goals.

identifying the drilling fluid functions within the system requirements.

matching the drilling fluid properties with the functions.

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profiling the performance under the varying condition for optimum additive

selection.

Throughout it is essential that the planning engineer liaise with all interested parties

involved with the well.

Firstly a ranked set of objectives has to be defined and agreed. For example: Is it an

exploration well? Then petrophysical logging may be important to monitor progress

against prognosis. Thus a near gauge hole with minimum fluid invasion would be a key

requirement. What type of logs are required? Some are sensitive to salt, others are

sensitive to oil.

Secondly, the specific fluid properties required to achieve the goals should be listed in a

planning table. Each property should then be examined specifically as to the requirements

throughout the circulating system. Having defined this model of optimum performance,

components can then be selected. Where variance from the ideal occurs the design should

be re-examined, with respect to the prioritised objectives, to gauge the impact that less

than maximum performance may have.

As well as satisfying the operational objectives materials chosen must meet a number of

"common requirements" such as HSE, compatibility with the make-up water and

compatibility with other additives.

Once the potential components have been identified, on a performance basis, then, and

only then, should the economics be reviewed. The costs examined should be on an

overall well basis. A balance must be always be sought between combating foreseeable

problems and overkilling all possible eventualities.

1.1.1.41.1.1.4 ECONOMICS ECONOMICS

One of the major, and perhaps the most influential, planning and operating parameters is

'cost'. "Cost control" and "expense reduction" have developed as everyday catch phrases

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within our industry, and rightly so. We have finite resources of funds with which to find,

develop and produce hydrocarbons.

Our goal is to reduce the cost of the whole operation. We must be careful not to just focus

on the price on individual products or elements. We can all calculate that saving 20% on

a US$1,000 item is not equal to a consequential loss of 1% on a US$40,000 operation due

to using a sub-optimal drilling fluid. The key objective is to minimise the cost of well

construction and maximise productivity.

For example, compare a reasonably quality bentonite based drilling fluid, costing

approximately US$50/m3, versus a more expensive polymer based fluid, costing around

$88/m3. Initially it would appear that the bentonite based fluid offer significant savings

over the polymer fluid.

However, consider the implications when drilling through the reservoir section of a well

to be completed barefoot. If the damaging nature of the bentonite filter cake, which is

chemically inert, reduces the production from an estimated 1,000 m3 per day to 900 m3 .

A remedial stimulation treatment to remove the damage could cost upward of $50,000. It

is easy to see that it would not take too long to lose any advantage gained from the

cheaper drilling fluid. This is not to say that more expensive is better. The essential factor

is getting a fit-for-purpose product.

Drilling fluid planning must consider the overall effect and economics on the operation,

particularly the cost per barrel of production; this is the ultimate goal. Cutting corners in

one area may not necessarily result in a cost saving in the overall project. Maximising the

results is as important as, if not more so than, reducing the cost. The result from a

properly structured planning process will be the optimum fluid for achieving the specified

goals with the minimum overall operational cost, and thus give:

Maximum Return on Investment

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1.1.1.51.1.1.5 THE SCOPE OF DRILLING FLUID ENGINEERING THE SCOPE OF DRILLING FLUID ENGINEERING

The planning of a drilling programme, and the day-to-day execution of the programme,

involve the well engineer in subjects ranging from the chemistry of clay mineral

molecules to the maintenance of pressure control in the well. The following subjects are

covered to the required depth in this part:

Density and pressure gradients

Rheology

Hydraulics

Borehole instability

Clay chemistry

Inhibition

Invert oil emulsion systems

Contaminants

Temperature

Drilled solids

Drilling problems

Well control

Cementing

Drill-in, completion and well intervention fluids

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1.1.21.1.2 Density and pressure gradients Density and pressure gradients

1.1.2.11.1.2.1 INTRODUCTION INTRODUCTION

The process of laying down the various formations and the subsequent actions on the

ground by movements within the earth's crust create abnormal conditions in the rocks

through which the operation will drill. These create specific problems that the drilling

fluid must overcome.

Uncontrolled production of formation fluids and gases can be a safety risk, hazardous to

the environment and a loss of revenue for the Company and the asset holder. The drilling

fluid is the first line of defence against such occurrences. The second defence mechanism

is containment within the well.

The optimum density of the drilling fluid is a balance between exerting enough downhole

force to overbalance the pressure within the formation whilst not compromising the

integrity of the wellbore.

1.1.2.21.1.2.2 UNITS UNITS

Specific Gravity (S.G.) is the dimensionless ratio of a material's density compared to that

of a standard solution of fresh water at sea level.

Table 6.1.1: Units of Pressure, 'Fluid' gradient and density

Refer also to Appendix 1.

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1.1.2.31.1.2.3 FORMATION STRESS & PRESSURE FORMATION STRESS & PRESSURE

SEDIMENTARY ROCK FORMATION

Generally, in oilfield drilling the formations penetrated have been built up by the

deposition of sediments. As this process continues the underlying material is subjected to

increasing force. Interstitial water is gradually squeezed out and the minerals are

compacted into sedimentary rocks.

STRESSES

The stresses acting on the rock in the subsurface can be resolved into 3 orthogonal

components. These are called the principle stresses ( n).

Fig 6.1.2: Principle Rock Stresses

Normally both the vertical and horizontal principle stresses will increase with depth. The

two are related by the fact that the rock is laterally constrained by the neighbouring rock.

However regional tectonics may cause other effects. If the stresses are of different

magnitude then the convention is: 1> 2> 3.

The vertical, or overburden, stress is generally expressed as a gradient; S/z. This can be

derived by integrating the formation density log.

As a rule of thumb: Overburden Gradient. 22·6 kPa/m (1 psi/ft)

Each principle stress is composed of two elements: the stress exerted on the rock ( f) and

that exerted on the pore fluids ( f).

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NORMAL FORMATION PRESSURE.

The initial sediments are laid down with about 60 - 70%v water. This material is

gradually buried deeper and deeper under the slow process of deposition.

At a burial depth of approximately 1000 m (±3,000 ft) grain to grain contact occurs for

the majority of the minerals and the material is regarded as a rock. At this stage it

contains about 26 - 30%v water. In the mudstone/claystone /shale formations the water is

held as layers between the clay platelets by forces other than purely physical confinement

(bound water).

As the pressure increases from more overlying sediments, and the temperature rises with

burial, more water is stripped from between the layers of clay particles. At around

2,000m (±7,000 ft) sufficient energy has built up in the system to have fully dislodged

one layer of bound water from the clay structure. Further layers are removed by

approximately 5,000 m (±16,500 ft), 10,000 m (±33,000 ft) and 20,000 m (±65,000 ft).

Mixing with generated hydrocarbons, the released water slowly migrates through the very

low permeability environment of the clays until it finds a more permeable formation,

such as a sand. The excess fluid bleeds through this zone back towards the surface. With

geological time the pressure in the shale is relieved back to the equivalent of a column of

water to that depth. The pressure in the pore spaces is therefore equal to the hydrostatic

column of the water. The remainder of the overburden stress is supported by the rock

matrix. This is termed a 'normally' pressured formation.

The water escaping from the compacting clay formations leaves behind some of the

originally dissolved salts. With increasing depth the pore water has an increasing salinity

resulting in a higher fluid density. Thus the pressure exerted increases with depth. This

can be determined by integrating the resistivity log.

As a rule of thumb: A 'normal' pressure gradient of 10·5 kPa/m (0·465 psi/ft) can be used

to depths down to 3,000m.

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ABNORMAL PRESSURE

If at any time the shale, or the permeable formation, is isolated then the excess pore fluid

cannot bleed off. Then the increasing overburden will be born by the incompressible pore

fluid. Thus it will be overpressured by the added mass of the formations from the depth

where it was isolated to its current depth.

Rapid deposition, or regional tectonic movement, can create additional stress on the rock.

This can accelerate the release of bound water beyond the bleed off rate of the low

permeability shale.

An uplifted, isolated, formation will retain the original internal pressure. Leaks along a

fault, or through a bad cement job, can connect a lower, higher pressured formation with

a higher zone. These formations will have a higher than normal pressure gradient.

Any one of the above phenomena raises the pressure of the fluid in the pore spaces higher

than normal. This is termed an 'abnormally' pressured formation. Multiple overpressure

situations are sometimes termed 'supernormally' pressured formations.

SUBNORMAL PRESSURE

The opposite effect can occur when two faults drop a centre block, graben faulting. A

normally pressured zone is suddenly (in geological terms) at a depth greater than its

equivalent column of water pressure.

A reservoir, produced for some time, may be depleted to below the normal hydrostatic

pressure gradient.

1.1.2.41.1.2.4 FORMATION FRACTURE GRADIENT FORMATION FRACTURE GRADIENT

Subsurface formations have a limited capacity to withstand an imposed wellbore pressure

before they fail. Below 1,000 m failure will usually be a fracture in the vertical plane

perpendicular to the least principle stress.

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Normally the formations become more resistant to failure the more compacted (buried)

they are, thus the weakest rock exposed in the wellbore during drilling is usually at the

last casing seat.

MINIMUM FRACTURE INITIATION PRESSURE

The minimum pressure at which a formation will breakdown or fracture is denoted by the

expression:

Pi = Pf + 3 + T

Where: Pi = 'Fracture', 'formation breakdown' or 'leak-off' pressure

Pf = 'Formation' or 'pore' pressure.

3 = Minimum rock stress

T = Tensile rock strength (= 0 for uncemented formations).

TECTONICALLY STRESSED AREAS

Different horizontal stresses must be taken into account when calculating the fracture

gradient.

Figure 6.1.3: Fracture Gradient v Deviatio

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DEVIATED WELLS

Well deviation means that the overburden stress is no longer parallel to the well.

Therefore it must be included in the calculation. The software package STABOR gives

estimates of the fracture gradient as a function of tectonic stresses and wellbore deviation.

OFFSHORE APPLICATIONS

In onshore applications all stresses are effective from the surface. When drilling offshore

the overburden and fracture gradients are only effective below the sea floor, see Figures

6.1.4a & 4b. In deep water operations this can have a significant impact on maximum

fluid gradients and casing setting depths.

Figure 6.1.4a: Pressure Depth Plot - Onshore

Figure 6.1.4b: Pressure Depth Plot - Offshore

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ABNORMALLY PRESSURED FORMATIONS

The strength of the rock is proportional to the rock matrix stress. Abnormally pressured

pore fluids are supporting more of the principle stress and the rock matrix stress is lower.

Therefore the gap between the formation pressure and the fracture gradient will be lower.

FLUID LEAK OFF TEST

A direct measurement of Pi is sometimes carried out by pressurising the formation until it

fails. This is known as a 'leak-off' or 'micro-frac' test. In drilling operations the result is

often expressed as the Equivalent Maximum Mud Gradient:

EMMG = Current Mud Gradient + Pi/Df.

1.1.2.51.1.2.5 IMPACT ON DRILLING OPERATIONS IMPACT ON DRILLING OPERATIONS

Pore fluids in an isolated porous formation within a shale will also be over pressured.

However, unlike the shale, the contents will be mobile and can bled into a lower pressure

region very quickly; resulting in a kick.

The overpressured shale will want to relieve the pressure into the hole if the drilling fluid

pressure gradient is lower. However the extremely low permeability of the shale will not

let the pore fluid flow easily so the force exerts itself on the rock in the vicinity of the

borehole. If the shale is plastic (generally high water content, 10% to 30%; rapid burial

cause) it will deform and squeeze into the borehole (swelling shale). If the shale is firm

and brittle (generally low water content - < 7%; sealed venting of pressure cause) it will

spall off in pieces (sloughing shale).

Drilling into a subnormally pressured formation with a higher drilling fluid pressure

gradient can result in higher rates of leak-off. This can lead to differential sticking of the

pipe and reservoir impairment. If the overbalance is higher than the strength of the

formation then it will fracture resulting in loss of circulation.

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1.1.2.61.1.2.6 DRILLING FLUID DENSITY DRILLING FLUID DENSITY

For well control of subsurface pressures the drilling fluid pressure gradient must be equal

to or greater than that of the pore fluid. However it must not be so high as to exceed the

fracture gradient of the weakest zone.

WEIGHTING MATERIALS

Salts & Brines

The liquid phase of the drilling fluid will have a specific density or gravity. The common

base fluids are water and oil (SG = ±0.8). The density of water can be increased with

salts.

Brine densities are reduced at higher temperatures, due to thermal expansion, but are

increased at higher pressures following compression. For both effects corrections have to

be applied during the design and operation of a brine.

Temperature correction: 2 = 1 - (ÆT)

Where = Æ/ÆT correction (kg/m3/°C)

Pressure correction: 2 = 1 + (ÆT)

Where = Æ/ÆP correction (kg/m3/100kPa)

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Solids

Insoluble material may be suspended in the drilling fluid to raise its bulk density to

increase the effective hydrostatic pressure.

1.1.31.1.3 Rheology Rheology

1.1.3.11.1.3.1 INTRODUCTION INTRODUCTION

One of the most influential properties of the drilling fluid is its viscosity. Understanding

the role of viscosity in drilling, and other operations, and being able to match viscosity

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requirements to the conditions prevalent for that requirement is a key factor in optimising

the efficiency of the fluid.

1.1.3.21.1.3.2 TERMINOLOGY TERMINOLOGY

Rheology

The science of the deformation and flow of matter. Common usage - the analysis of a

fluid's viscosity behaviour under variable shear rate conditions.

Shearing Stress

A stress that acts tangentially to a face.

Shear Stress ( )

Shear force per unit area of action. [Newtons per square meter or Pascals]

Shear Strain ( )

Shear displacement divided by the thickness of the fluid element. [dimensionless]

Shear Rate ( /( t, but usually written as )

Time rate of change of the shear strain (or shear strain rate). [sec-1. "reciprocal seconds"]

This is the condition which changes most throughout the circulation system. Fluid, in

laminar flow, moves as parallel layers and has a profile of changing velocity with

distance from the walls. The Shear Rate is an average representation of the movement

relationship of the layers of fluid in a cross section of the flow path.

Viscosity (µ)

A fluid's internal resistance to flow (the shear stress at the shear rate). [Newton seconds

per square meter, or Poise]

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Newtonian Fluids

The shear stress of the fluid is constantly proportional to the shear rate ( =µ ).

Non-Newtonian Fluids

The shear stress of the fluid is not constantly proportional to the shear rate. There are a

number of different models and the key ones are discussed later in this Topic.

Pseudoplastic Fluids

Non-Newtonian fluid where the viscosity varies inversely to the shear rate; it is thinner at

higher shear rates ("Shear Thinning").

Thixotropic Fluids

Time dependent viscosity. Such fluids exhibit a hysteresis (difference) between the shear

stress/shear rate plot when applying and removing energy to the fluid. The degree of shift

is often related to a realignment of particles with attractive tendencies.

Figure 6.1.5: Viscosity-Time relationship for a thixotropic fluid

Gel Strength

Thixotropic fluids often exhibit an increase of viscosity with time when at rest. In drilling

fluid terminology this is referred to as the Gel Strength. [Newtons per square meter or

Pascals]

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Rheopectic Fluids

Time dependant fluids exhibiting the opposite phenomenon to thixotropic fluids. Often

high solids content slurries have rheopectic behaviour.

Yield Stress

The Shear Stress required to overcome internal inertial forces.

Turbulent Flow

Chaotic flow characterised by intense mixing caused by eddies.

Laminar Flow

Smooth flow that is devoid of disturbances such as eddies, characterised by parallel layer

movement.

Reynolds Number (N Re)

The ratio of the inertial forces to the viscous forces. [dimensionless]. Commonly used to

determine the velocity at which a fluid's flow regime changes from laminar to turbulent.

1.1.3.31.1.3.3 DRILLING FLUID VISCOSITY MODEL DRILLING FLUID VISCOSITY MODEL

An analysis of the various viscosity requirements on the drilling fluid, throughout the

circulating system, against the influencing conditions will give us a model of the ideal

drilling fluid rheology.

VISCOSITY REQUIREMENTS FOR DRILLING

Inside the drill string the fluid is purely commuting to the bit. No constructive (or

destructive) work is being done. At the high velocities required in the drill string,

overcoming the fluid's internal resistance to flow consumes a large proportion of the

input pump energy. If the viscosity in this region can be kept to a minimum then this

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energy can be conserved and better used to assist drilling. The normal flow rate range in

the drill string corresponds to a shear rate range of approximately 200 to 2,000 sec-1.

At the bit the fluid is passing through small nozzles to generate higher velocities to

impact onto the rock to assist drilling. The functions of the fluid at this point are to cool

the bit, clean the bit, and remove the cuttings. The first two are a direct function of the

velocity of the fluid, which can be maximised as a consequence of minimising energy

losses in the drill string.

The third function is also influenced by the consistency of the fluid. If we imagine the

action of a roller cone bit; it is making very fine microfractures in the rock. When these

join up a cutting is generated. However the density of the fluid is normally maintained

above that of the formation pressure (well control). This differential pressure holds the

cutting in place. If the drilling fluid can permeate into the fractures it will equalise the

pressures around the cutting and lubricate the surfaces to facilitate easier removal. With

the high jet velocity created by the bit nozzle, the fluid exerts additional hydraulic force

to assist in removing the cuttings. If the consistency of the drilling fluid is thick like that

of honey it will not penetrate. If it is thin like water then the resistance to flow into the

fractures is significantly lower. Thus a very low viscosity is required at the drilling face.

The shear rate range involved is from 5,000 to 100,000 sec-1.

Once the fluid commences its upwards journey the shear rate environment is dramatically

reduced and the viscosity requirements are radically different. The generated cuttings

must be efficiently removed from the hole. Their vertical transportation is a function of

the uphole velocity of the fluid and their downward fall within that fluid (Stokes Law).

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If the diameter of the drilled hole is enlarged ("washed out") , and the fluid's resistance to

cuttings slip remains the same, then the transport efficiency will reduce, as shown in the

table opposite.

To ensure consistent cuttings transport the fluid must be able to increase its resistance to

the slippage of the cuttings inversely proportional to the fluid velocity. The annulus shear

rate in the range of 5 to 100 sec-1.

If the pumps are stopped then the uphole fluid velocity is zero. But the cuttings can

continue to slip. They can accumulate around the drill string and stick the pipe. Thus,

when at rest, the fluid must build a very high resistance to the cuttings settling. It is

normally accepted that the shear rate around a particle in a viscous fluid at rest

corresponds to a range of 0·1 - 1 sec-1.

When the pumps are restarted we do not want the fluid to have an excessively high

resistance to commence movement. This would be manifested as a high pressure at the

bottom of the hole. This could be sufficient to overcome the strength of the rock and

cause loss of whole fluid. Thus we want a minimum of thixotropy.

The profile of the velocity of the various parallel layers influences the way in which the

cuttings are transported. If the profile is parabolic as in Newtonian fluids the cuttings will

move outwards to the lower velocity layers, thus slowing their net velocity. If the profile

is flatter (higher pseudoplasticity) the cuttings will tend to stay in the same position in the

fluid for more efficient transportation.

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If the ratio of the inertial forces to the viscous forces exceeds a certain value (N Re 3,000 -

4,000) then the fluid flow will become turbulent. The magnitude of the transition point is

controlled (proportionately) by the fluid's ability to react to the rate of the imposed shear

(pseudoplasticity).

Inhibiting invasion of fluid into a permeable zone is essential to protect the formation and

facilitate higher quality data. The viscosity of the fluid can be utilised to limit fluid loss

(in addition to or in place of a filter cake). A thick fluid consistency will have a high

resistance to flow along the permeation channels limiting the ability of the fluid to

invade. However in the reservoir section, this fluid must be removed for maximum

recovery of the hydrocarbons. Therefore the invading fluid, with its high resistance,

needs to thin rapidly on the application of a greater force acting towards the borehole and

flow easily out of the formation. The shear rates on entering a typical permeable sand

formation are in the range of 0·01 to 0·5 sec-1.

When the cuttings laden fluid reaches the surface, it must be rapidly processed to limit

recycling of the drilled material. Due to the design of the fluid so far settling of the

cuttings would take too long. Solids removal equipment utilise inertia, momentum and

acceleration differences (due to mass differences between the fluid and the particles) to

facilitate liquid/solid separation. Fluid resistance to the movement of the solids should be

at a minimum. The processing equipment shear rate usually corresponds to the range of

200 to 5,000 sec-1.

IDEAL MODEL

Analysing the viscosity requirements of the drilling fluid

leads to an ideal model being:

Above 200 sec-1 minimum viscosity.

200 - 5 sec-1 a controlled viscosity inversely proportional with shear

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rate.

5 - 1 sec-1a very high viscosity, easily thinning with an increase in

the shear rate.

Below 1 sec-1an ultra high viscosity, rapidly thinning with an increase in

the shear rate.

OPTIMUM MODEL

Common drilling fluids do not behave on such an exacting basis. However most behave

as pseudoplastic fluids. What is required is a best match viscosity profile to the ideal

model established; an optimum model.

Figure 6.1.6: Optimum Viscosity Model for a Drilling Fluid

The optimum model is a viscosity profile where the viscosity at the higher shear rates is

thinner and at the lower shear rates is ever increasing with a reduction in shear, without

any hysteresis between the increasing and decreasing shear rate curves. This describes a

fluid with rheological profile termed non-thixotropic, pseudoplastic.

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This model forms the basis for the specification for the drilling fluid rheology. Each hole

section will have a specification that addresses the individual needs of the drilling

operation and resultant product.

1.1.3.41.1.3.4 RHEOLOGICAL MODEL RHEOLOGICAL MODEL

Historically three methods have been commonly used to describe the viscous behaviour

of a drilling fluid; the Marsh Funnel Viscosity, the Bingham Plastic Rheology Model and

the Power Law Rheology Model.

1.1.3.4.1 MARSH FUNNEL VISCOSITY (MFV)

The Marsh Funnel Viscosity test measures the time taken for a unit volume of drilling

fluid to flow through a standard tube section. The test has a number of limitations. It

generates a high shear rate, in the range of 2,000 to 20,000 sec-1, and provides only a

single data point. Due to the complexity of drilling fluid composition it is not possible to

extrapolate this data to other ranges of shear. Thus the MFV cannot be used to evaluate

performance in those regions of the circulating system. In addition the primary

controlling parameters vary throughout the test making detailed analysis highly

complicated. However due to the simplicity and robustness of the Marsh Funnel it

remains the most useful tool for quick, routine monitoring for change.

1.1.3.4.2 BINGHAM PLASTIC MODEL (PV & YP)

The Bingham Plastic Model describes a fluid which is Newtonian and has an initial yield

stress. Mathematically the model can be represented as:

t= PV(g) + YP

The slope of the line (Newtonian viscosity region) is called the Plastic Viscosity (PV) and

the intercept with the y axis (initial yield stress) is the Yield Point (YP). The model

descriptors are calculated from two readings (Topic, COAXIAL DIRECT READING

VISCOMETER (VG METER, VISCOMETER OR RHEOMETER)) taken at 1,022 and

511 sec-1 (to give the data directly in viscosity units).

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PV = [600 rpm Reading] - [300 rpm Reading]

YP = [300 rpm Reading] - [PV]

As can be seen in Figure 6.1.8, the model does approximate the typical drilling fluid

viscosity profile in the medium shear rate ranges and therefore can be used for

interpretation in this region. The predominant factor affecting this part of the viscosity

profile is the concentration of solids in the drilling fluid. The PV is a useful indicator of

resistance in the drill string. The model deviates significantly in the lower shear rate

range, corresponding to the annular regions. The YP is not a usable descriptor for

interpretation of performance.

Figure 6.1.8: Rheology Model Fits for Common Drilling Fluid Viscosity Profiles

As MFV and PV are applicable for only medium and high shear rate ranges they are

useful for a quick look evaluation but cannot be used to predict performance at the lower

shear rates of the annulus region.

1.1.3.4.3 POWER LAW MODEL (n & K)

The Power Law Model describes a fluid which is Non-Newtonian (Pseudoplastic) with

no initial yield stress. Mathematically the model can be represented as:

2828

= K()n or µ = K()n-1

When plotted on a log-log graph of viscosity versus shear rate it yields a straight line.

The Flow Index ('n') is the slope of the line (degree of pseudoplasticity). The Consistency

Factor ('K') is the vertical displacement of the line (thickness or consistency). The model

descriptors are calculated from readings taken at 511 and 5.11 sec-1. (one corresponding

to the drill string and the other to the annulus).

n = (Log [300 rpm Reading] - Log [3 rpm Reading])/2K = 5.11 x [300 rpm Reading] / 511n

As can be seen in Figure 6.1.8 the model does approximate the typical drilling fluid

viscosity profile at the lower shear rate ranges and therefore can be used for interpretation

in this region. A lower 'n' indicates a larger viscosity change with variations in shear and

is primarily influenced by the type of viscosifier. 'K' is the consistency of the fluid and is

primarily influenced by the concentration of the viscosifier.

1.1.3.4.4 COAXIAL DIRECT READING VISCOMETER (VG METER,

VISCOMETER OR RHEOMETER)

The VG meter is used to provide multiple data points to for more detailed analysis of the

drilling fluid's viscosity profile. The outer rotating sleeve speed can be varied to produce

different shear rates in the annulus around the bob. Shear stress is measured by the

deflection of the dial attached to the bob which is held by a spring of known resistance.

The instrument configuration is such every 1° of deflection is 5.11 cp/sec-1.

2929

Figure 6.1.7: Co-axial Viscometer

1.1.3.51.1.3.5 MODEL DESCRIPTION MODEL DESCRIPTION

The Power Law Model of rheology can be used to describe the key annular region

parameters of the optimum model:

sufficient carrying and suspension ability to remove the cuttings.

a rate of viscosity change with shear variation sufficient to maintain effective

hole cleaning.

The PV of the Bingham Plastic Model is used when calculating pressure losses in the

drill string.

1.1.3.5.1 DRILLING FLUID RHEOLOGY SPECIFICATION

Using a ranked list of objectives the design engineer must then determine what will be

the 'fit-for-purpose' rheology required. This, of course, will be influenced by many

variables; including hole sizes, formations, data requirements, cementation requirements,

rig equipment etc. However the two over-riding factors will be the transportation

efficiency required and the cuttings settling rate when the fluid is acquiescent (not

moving). Once these have been determined, ranges for the Power Law indices 'n' and 'K'

can be derived.

3030

These are the specifications which the fluids engineer will use to prepare and manage the

rheology of the drilling fluid.

1.1.3.5.2 FIELD MONITORING

The essential factors in field management of drilling fluid rheology are:

a quick recognition of any deviation from the specification.

distinguishing the type and degree of non-conformance.

identifying the probable cause of, and remedial action for, the change.

Therefore any monitoring procedure must produce a fair representation of the fluid in use

against the optimum model established.

Neither of the two classic models fully represents the typical viscosity profile of a field

used drilling fluid. More complicated models exist. However the interpretation of them is

correspondingly more complex and other factors, such as instrument error and well

irregularities, negate their practical use.

The dial readings from the viscometer plotted directly onto a log-log graph give a visual

representation of the viscosity profile of the drilling fluid. This representation can be

easily compared against the fluid's specification. Without calculation, the fluid can be

qualitatively, and fairly reliably, assessed for its capacity to do the job. In addition, errors

in reading the instrument are quickly spotted as the resultant graph will not be smooth.

Quantification of performance using the graph derived data will be more accurate.

The key benefit of this system of rheology monitoring is the simplicity for field

application of a very sophisticated, and relatively accurate representation of performance

against the specification model. This is particularly useful when troubleshooting

problems. The specific short falls can be easily identified and readily explained to

anyone. Also when the fluid is blamed for an operational deficiency, its performance in

that region of shear rate can be clearly and visibly assessed.

3131

1.1.3.5.3 FIELD APPLICATION

Product Performance

Having identified the optimum model of viscosity required, then available viscosifiers

can be evaluated functionally for performance and then economically to select the most

fit-for-purpose material.

Figure 6.1.9: Direct Viscosity Plot

Using the plot, functional efficiency is evaluated against the optimum model. A material's

strong and weak points can be properly compared with other materials. After eliminating

poor performance material the remaining contenders can be economically evaluated by

comparing the cost to prepare a slurry with a specific consistency.

Problem Analysis

When a change in viscosity is identified (say through a change in MFV) the specific

region of variation can be easily identified and assessed. This will direct the engineer to

the right area for remedial action. Having identified the area for corrective treatment, and

having an evaluation of materials available he can formulate an effective treatment.

3232

Pilot Testing

The engineer can pre-test the potential impact of a treatment by pilot testing and

comparing the two plots. This will also give him an assessment of how much material

will be needed to return the fluid to specification.

1.1.3.61.1.3.6 CONCLUSION CONCLUSION

The MFV is useful to monitor for change. The Bingham Plastic and Power Law Models

should only be used as a quick look analysis. They should not be used as specification

parameters, performance indicators nor as the basis for assessing non-conformance or

recommending remedial treatments.

The direct plot of the fluid viscosity versus the shear rate is a more reliable drilling fluid

management tool.

It provides a specification the drilling fluid that targets operational performance.

Rheology modifiers can be logically chosen based upon true performance and

economics.

Non-conformance can be properly assessed and remedial treatments verified.

The more readings that can be taken (i.e. Fann 6 or 9 speed) the more accurate will be the

evaluation.

1.1.41.1.4 Hydraulics Hydraulics

1.1.4.11.1.4.1 INTRODUCTION INTRODUCTION

Managing the effective use of available hydraulic energy to assist hole excavation is a

key factor in drilling optimisation.

IMPACT FORCE (I.F.)

The bit nozzles provide a high energy jet to:

3333

inject fluid into the microfractures to equalise pressure around, and apply

hydraulic lift to, the cuttings.

flush away the newly made cuttings from the drilling face.

blast the bit teeth and cutters to keep them clean.

circulate heat away from the high energy areas of the bit (cutters and bearings)

Maximising the Impact Force (I.F.) and Crossflow Velocity are the key factors in

optimising bit hydraulics.

EQUIVALENT CIRCULATING DENSITY (E.C.D.)

Energy is consumed in circulating the fluid up the annulus. This manifests itself as an

additional pressure effect on the bottom of the hole. This pressure could exceed the

strength of a weak formation resulting in a fracture and loss of integrity.

MANAGING ANNULAR VELOCITIES

A minimum velocity is required for efficient cuttings removal and a maximum velocity is

set to avoid erosion of weak formations.

CALCULATION ACCURACY

The pressure drop calculations for the bit nozzles are normally accurate. Calculated

pressure drops in the drill string are also generally within acceptable limits. However

calculating pressure drops in the annulus are subject to many indeterminable variables,

such as hole size, wall roughness and downhole fluid viscosity.

1.1.4.21.1.4.2 OPTIMISATION THEORY OPTIMISATION THEORY

1.1.4.2.1 OBJECTIVE

To optimise the application of input hydraulic energy at the bit to assist hole excavation

whilst maintaining the other circulation criteria.

3434

1.1.4.2.2 CONTROLLING FACTORS

Minimum & Maximum Flow Rate

The maximum flow rate is dictated by two factors:

avoiding hole erosion,

controlling the total pressure in the annulus acting on the formation at its weakest

point.

Up to a certain shear rate the viscosity of the fluid can control the fluid flow to discrete

laminae moving in one direction (Laminar Flow). Above this shear rate, excess internal

friction begins to create random disorder causing eddies to develop (Transitional Flow).

At higher shear rates greater disruption occurs (Turbulent Flow). In practice it is

considered that this transition is demarcated by a Reynold's Number (NRe) of 3,000.

It is desirable to keep the fluid in laminar flow in the annulus as an essentially non-

moving layer against the borehole wall will act as a protective barrier against erosion. In

turbulent flow, the random action of the fluid disrupts this layer and impinges directly

upon the formation.

Therefore the maximum flow rate should be less than transition to turbulent flow (Critical

Velocity; Vc).

The loss of energy in circulating the fluid up the annulus manifests itself as a pressure

drop (Pa) which acts on the bottom of the hole; in addition to the pressure due to the

Hydrostatic Head of the column of the fluid (Pm). The total effective pressure (ECD)

should not exceed the pressure at which the formation fractures and takes fluid ingress

(Equivalent Maximum Mud Gradient or Leak Off Pressure). This limit will be derived

from offset well experience or a Leak-Off Test. In certain circumstances, such as deep,

slim and high pressure drilling, the maximum circulation rate may be governed by an

ECD ceiling.

The minimum flow rate will be determined by the required hole cleaning efficiency.

3535

As a rule of thumb the minimum Va should be >2 times the Vs. Refer also to the Well

Engineers Notebook, page E-5.

Surface Pressure Limitations

The surface equipment of the rig has a maximum working pressure rating. Normally the

contractor does not like to exceed 85% of this as maintenance requirements dramatically

increase.

Thus there is a maximum pressure that can be applied to the circulation of the drilling

fluid.

Friction Losses in the Circulating System

Energy is consumed in overcoming frictional resistance to moving the fluid around the

circulation system. The drilling fluid design should target reducing these scavenger losses

to an acceptable range that allows sufficient energy to be available to assist drilling

progress.

Input data inaccuracies preclude individual assessment of these pressure losses. In

addition they are all non-productive. Therefore, for the purposes of optimising energy

application at the bit they can be regarded as a single entity.

Minor changes in a drilling assembly will not normally have a significant effect on PS.

However adjustment for some downhole tools, such as turbines or mud-motors, can be

made the with manufacturer's data.

Bit Nozzles - Total Flow Area

Having determined the limitations and controlling factors, the complete circulating

system can then be evaluated to select the bit nozzles that maximise the amount of energy

that can be directed to the bit.

3636

1.1.4.31.1.4.3 OPTIMISING PROCESS OPTIMISING PROCESS

GRAPHICAL METHOD

A graphical process for optimising bit hydraulics is:

1) Determine the operating limits:

Maximum pump rate based upon maintaining laminar flow in the annulus or

limiting the ECD.

Minimum pump rate to ensure adequate hole cleaning.

Maximum allowable surface pressure.

2) Determine the available pressure drops at the bit versus the pump rate:

At the end of a bit run, record the circulating pressures (P t) at three pump rates

(Q); these should be spread across the working range for the hole (also applicable

to the Well Control Worksheet).

For each flow rate calculate the pressure drop across the bit nozzles or TFA (Pb)

Subtract Pb from Pt to determine the remaining 'system' pressure loss (PS).

confirm the actual nozzles when the bit is recovered.

3) Create a graph with the operating limits:

On log-log paper draw a boundary line at the minimum and maximum (annular

velocity) pump rates.

Draw a boundary line for the maximum allowable surface pressure.

Plot the total circulation pressures (Pt ) against pump rates.

3737

At the intercept with the maximum surface pressure draw a boundary line for the

maximum pump rate; if lower than the previous maximum allowable (annular

velocity) flow rate.

4) Create a plot of the 'system' pressure losses versus pump rate.

Plot the determined PS against the respective circulation rates.

Draw a line through the 'system' losses inside the operating limits.

This line can be subsequently interpolated/extrapolated for any circulating rate.

5) Plot the design criteria line:

Maximum I.F. occurs when PS = ±0·5 Pt

6) Determine the optimum pump rate.

Intercept of the 'system' pressure loss with the design criteria line.

If the intercept is outside of a boundary limit then review the limit, drilling fluid

properties or design criteria and determine the required pump rate as appropriate

for the operation.

7) Calculate the total flow area to achieve the optimum or available pressure drop at the

bit.

Subtract PS at the optimum required flow rate from the maximum allowable

surface pressure.

Use the Well Engineer's Notebook, page E-3, to calculate the total flow area

required through the nozzles.

8) Determine the nozzles required to approximate the flow.

3838

Use the table on page E-4 of the Well Engineers Notebook to choose the nozzles

which give a flow area closest to the calculated area.

If the nozzles are below a minimum size (to avoid plugging off) then re-examine

the flow properties to increase the transition flow rate (Vc) to allow an increase in

the pumping rate or reduce PS.

Alternatively blanking off one nozzle can allow smaller flow areas with larger

jets.

CALCULATION METHOD

The Well Engineers Notebook (page E-3/4) contains all the necessary equations for

optimising bit hydraulic horsepower or jet impact force by means of calculations.

1.1.4.41.1.4.4 ROUTINE MONITORING ROUTINE MONITORING

Periodic monitoring is restricted to analysing the ECD to ensure well integrity and

maintain pressure control.

As stated previously annular pressure drop calculations are inappropriate due to input

data inaccuracy. The most practical method to determine the ECD is to calculate the drill

string and bit hydraulics and subtract them from a reasonably accurate standpipe pressure

(choke gauge). Direct calculations should only be used in critical cases and must be

properly calibrated against measured total annulus pressure losses.

1.1.51.1.5 Borehole instabilityBorehole instability

1.1.5.11.1.5.1 INTRODUCTIONINTRODUCTION

An unstable borehole can pose major problems for the drilling, and subsequent,

operations:

Fill on trips increasing the drilling time and reducing bit life.

Swelling formations producing tight hole.

3939

Hole washout compromising cementation.

Caving formations that may result in stuck pipe.

There are many symptoms but there only a few causes of borehole instability. The key to

effective problem solving is identification and treatment of the source, not the effect.

Details of the various preventative or remedial actions are covered in subsequent

subtopics.

1.1.5.21.1.5.2 HOLE EROSION HOLE EROSION

CAUSE

Hole erosion results from the hydraulic impact on formations with poor inter-grain

cementation. Generally it is caused by turbulent fluid flow in the annulus or excessive

circulation in one place with the bit off bottom.

IMPACT

The annular fluid velocity will be reduced in enlarged hole sections. If the drilling fluid is

not highly pseudoplastic, the cuttings can concentrate in this area. Eventually they may

form a 'mud ring' or ball of agglomerated cuttings, which in severe cases can lead to hole

pack-off and stuck pipe.

Many logging tools require contact with the borehole wall. If the washout is irregular the

tool contact will be intermittent giving poor data. If the hole is excessively large the tool

may not even contact the wall. Ledges may cause the logging tools to hang-up.

During well killing operations if a gas bubble encounters a washout it will expand

laterally and the height will reduce proportionately, changing the hydrostatic pressure. If

it re-enters a near gauge portion, the opposite will happen. Choke control will need to be

accurate and rapid to maintain the bottom hole pressure constant.

4040

Ledges may hold up casing, particularly in deviated holes. Good cementing practice

requires turbulent flow to ensure proper drilling fluid removal. Large washed out sections

may cause the flow to become laminar and induce channelling or poor drilling fluid

removal. Eddies in the flow may cause entrapment of drilling fluid pockets in the cement.

PREVENTION

Keep the flow regime laminar, where possible. Maintain highly pseudoplastic

rheology (n<0·5); the critical Reynold's Number is inversely proportional to the

flow Index 'n'.

High low shear rate viscosity has been successfully used to resist movement of

loose formation grains. Along with the reduced flow rate requirements this makes

an excellent fluid for unconsolidated formations.

Minimise circulating off bottom. Always reciprocate the pipe a full kelly length.

When circulating bottoms up, remove one or two pipe joints half way through so

as to relocate the impact area.

In silty formations examine the possibility of water sensitive clays causing

further destabilisation. If suspected, test with small treatments of inhibiting

chemicals or polymers.

Use of K+ to combat such instability has proven detrimental in some areas. Lattice

collapse is thought to lead to mechanical instability. One such area is in the northern

region of the Malay Basin.

CURE

None. Once the problem has manifested itself the only action is careful planning for

subsequent activities.

4141

1.1.5.31.1.5.3 SWELLING SHALE SWELLING SHALE

CAUSE

Swelling shale is the plastic deformation into the wellbore of high water content shales.

This often occurs in the younger formations in the upper hole sections. It is the result of

water imbibition by a smectitic shale. In deep, older, formations it is caused by entrapped

fluids (abnormal pressure).

IMPACT

The annular diameter is reduced. The drill string, logging tools and casing may not easily

pass through. Increased annular friction pressure losses may raise the ECD above the

fracture pressure for a lower zone. .

PREVENTION

Ensure that the fluid pressure gradient is higher than that of the formation.

For the younger clays, evaluate an inhibitor to mitigate water imbibition effect.

Cl-, Ca+2 and PO-4 generally prove effective. The reaction rate of K+ is too slow.

Encapsulating polymers are ineffective in stopping water imbibition over a long

period; though they may assist in maintaining cuttings integrity.

CURE

If the problem is not underbalanced drilling fluid density, apply an inhibitor.

Increase dosage gradually and observe reaction. If no effect is noted, a long chain

encapsulating polymer may assist in the short term.

The problem is most easily handled if water imbibition is controlled from the

outset. Once it has started it is generally very difficult to control or reverse.

4242

1.1.5.41.1.5.4 SPALLING SHALE SPALLING SHALE

CAUSE

Spalling shale is caused by the formation pressure exceeding the drilling fluid

hydrostatic pressure; Pf > Pm. The rock's low permeability resists pressure

equalisation. If the differential is higher than the tensile strength the rock will fail

by 'exploding' into the wellbore. The spalled pieces are often long and twisted;

like shrapnel.

IMPACT

Apart from hole enlargement, covered above, spalling can have a major impact

on drilling. Large pieces can quickly build up in the annulus and can pack-off

around the larger diameters (i.e. stabilisers and bit); blocking circulation and

sticking the pipe .

PREVENTION

Ensure that the fluid pressure gradient is higher than that of the formation.

(Except when underbalanced drilling is being undertaken, the borehole pressure

should always be higher than the formation pressure. If not, then a kick would

result if a porous and permeable zone is penetrated.)

CURE

Raise the drilling fluid density. Examine the cuttings on the shakers for

confirmation of the effect of the treatment. Be aware, however, of the fracture

pressure limit.

4343

1.1.5.51.1.5.5 SLOUGHING SHALE SLOUGHING SHALE

CAUSE

Sloughing shale is caused by brittle failure resulting from differential rock stress. This

can be due to tectonic activity or deviation of the well bore from vertical. The rock can

fail in either tension or compression depending upon the orientation of the stresses to the

wellbore wall. The sloughed pieces tend to be slivers or flat shapes for tensile failure and

block shapes for compressive failure.

IMPACT

Comparable with spalling shale.

PREVENTION

The drilling fluid hydrostatic cannot fully oppose the maximum rock stress.

However maintaining a positive pressure overbalance against the formation

pressure will help to hold the failed rock pieces in place.

Wellbore fluid communication with the pore fluid will raise the near wellbore

pore pressure and negate the differential effect. Pore isolation techniques such as

TAME (Thermally Activated Mud Emulsion) or IOES (Invert Oil Emulsion

Systems) will maintain the differential effect.

In some formations water imbibition can accelerate destabilisation. If suspected,

test with small treatments of inhibiting chemicals, generally Cl- and K+.

CURE

The problem is most easily handled if a positive overbalance is maintained from

the outset. Once sloughing has started it can be very difficult to control or

reverse.

4444

Slowly raising the fluid density can maintain a positive differential for a longer

period.

Apply pore isolating techniques; TAME or IOES.

If the problem is not underbalanced pressure, apply an inhibitor. Increase dosage

gradually and observe reaction. If no effect is noted a long chain encapsulating

polymer may assist in the short term.

1.1.61.1.6 SALT FORMATIONS SALT FORMATIONS

CAUSE

Salt formations can cause problems as a result of wellbore instability through plastic

deformation or dissolution by undersaturated water based fluids.

EFFECT

Plastic deformation results in a reduced wellbore size while dissolution causes hole

washout.

PREVENTION

Sufficient fluid density to resist plastic flow; for the period needed to drill and

case the section.

Use a saturated salt water based drilling fluid or an inert IOES.

CURE

If the problem is not severe, use the preventative measures above.

Plastically deformed salt can be washed out with an undersaturated brine.

There is no cure for washed out salt sections - these cannot be replaced.

4545

1.1.71.1.7 Clay chemistry Clay chemistry

1.1.7.11.1.7.1 INTRODUCTION INTRODUCTION

The vast majority of formations drilled are marine, clastic (sedimentary) formations. The

bulk of these are mudstones and shales, which are predominantly composed of clay.

Therefore it is helpful to know something about the basic chemistry, composition and

reactive nature of these minerals.

1.1.7.21.1.7.2 CLAY TYPES CLAY TYPES

1.1.7.2.1 GENERAL COMPOSITION

The normally encountered clays are similar in composition and structure. They are

formed by the weathering of igneous minerals. They are then transported by the streams

and rivers and deposited in lakes, swamps and the seas. Burial compacts them into

sedimentary rocks.

Each clay lattice is made up of two sheets of silica tetrahedra with a central sheet of

alumina octahedra. The tips of the tetrahedra point towards the centre of the lattice, and

with one of the hydroxyls of the octahedral sheet form a common layer. The lattices are

continuous in the x and y directions (horizontal plane) and are stacked one above the

other in the z direction (vertical).

4646

Figure 6.1.10: Clay Lattice Building Blocks

The O-2 layers of each tetrahedra base are adjacent to O-2 layers of the neighbouring

lattice, with the consequence that there is a weak bond and an excellent cleavage plane

between them. In between the lattices, bound water is oriented such that the two

hydrogens face each layer of oxygens.

Differences between the various clays encountered are primarily due to substitution of the

aluminium in the central octahedral layer and silica in the outer tetrahedral layers by

other multivalent cations. This creates a charge imbalance which is compensated by

adsorbed exchange of cations in the interlattice zone. Chlorite is the exception in that the

interlattice zone is filled with a further molecular sheet structure.

1.1.7.2.2 DIAGENESIS

Diagenesis is the sequence of increasing modification (diagenesis), through this

substitution and exchange.

Feldspar (source mineral for weathering)

Smectite

Mixed Layer Clay (a smectite to illite graduation)

Illite

Muscovite

Conversion to the next clay group in the sequence is catalysed by increasing input energy

from the depth of burial and geothermal heat. The sequence is marked by a reduction 4747

from high reactivity, to water and ion exchange, to inert interlattice activity. This is a

result of the ever decreasing interlattice separation and the binding effect of the

Potassium (K+), which 'fixes' adjacent clay platelets into their most stable condition.

Figure 6.1.11: Clay Diagenesis Cycle

1.1.7.2.3 SMECTITE (MONTMORILLONITE, BENTONITE)

Slight substitution in the clay lattice results in about 0·66 anionic (-ve) charge of per cell

unit. This is balanced by exchangeable cations (+ve) adsorbed between the unit layers.

A main feature of the smectite group is the wide interlattice gap and weak bonding.

Water and other polar molecules can enter between the unit layers and cause the lattice to

expand in the z direction. The interlattice dimension varies from 9·6 Å to complete

separation.

4848

Figure 6.1.12: Smectite Clay Structure

The interlattice cations are loosely bound and can be readily exchanged; with the

replacement power ranking of Li<Na<K<Ca<Mg<Al.

The two main exchangeable cations are Na+ and Ca++. The multivalent cation smectite is

less reactive with water. Calcium more readily exchanges with sodium than sodium

replace calcium. This phenomenon is used in drilling fluid design for stabilising smectite

clay sections.

The Potassium ion is unique in that its hydrated size, and coordination properties, fit

exactly into the basal oxygen sheet of the tetrahedral layer. When exchanged for the other

cations the interlattice distance decreases to the minimum height, the potassium is very

difficult to remove and the lattices are essentially fixed. This is the final stage in the

diagenesis of smectite to illite.

This phenomenon is used to stabilise clays that have been exposed to sufficient pressure

and temperature for diagenesis, but where the original depositional environment was

deficient in potassium (i.e. lacustrine).

4949

1.1.7.2.4 ILLITE

Illite is a transitional stage in the diagenesis of smectite to muscovite. The lattice

structure is the same as smectite except that there is a higher degree of substitution of Al+

++ for Si++++. The charge deficiency is increased to 1·3 - 1·5 per unit cell, mostly in the

silica sheets and therefore closer to the surface. K+ is the fixed interlattice cation.

Because of these differences, the illite lattices are relatively fixed in position, so that

polar ions cannot enter readily between them and cause expansion. Thus they are not very

sensitive to water.

Figure 6.1.13: Illite-Muscovite Clay Structure

The traditional shale classification (after Mondshine) shown in Table 6.1.6 clearly shows

the diagenetic trend. With increasing burial, the water content decreases, the density

increases, the salinity rises and the amount of reactive (high Cation Exchange Capacity)

clay decreases. Exceptions are formations with abnormal pressures (high water content

and porosity) and where the original deposition environment was deficient in potassium

(high CEC).

5050

This classification can be used to broadly categorise shales into different inhibition

requirements, as shown in Table 6.1.7.

1.1.7.2.5 CHLORITE

Chlorite is a mixed layer clay derived from the different source minerals. The structure is

basically the same as the other clays except that in between the mica layers is a free

floating alumina octahedral 'brucite' layer. The deficiency charge on the talc layers is

balanced by the excess charge on the brucite sheet. The bonding between the sheets is

partly electrostatic and partly due to adjacent sheets of oxygen and hydroxyl ions. The

fixed nature of the structure precludes adsorption of dipolar molecules.

Thus it is non-reactive to water.

5151

Figure 6.1.14: Chlorite Clay Structure

1.1.7.2.6 KAOLINITE

Kaolinite has a slightly different structure. It is a two layer type which is equi-

dimensional in the x and y directions. The charges within the lattice are balanced. Hence

there are no adsorbed interlattice ions and it is non-expanding.

Thus it is non-reactive to water.

Figure 6.1.15: Kaolinite Clay Structure

5252

1.1.81.1.8 Inhibition Inhibition

1.1.8.11.1.8.1 INHIBITING CHEMICALS INHIBITING CHEMICALS

1.1.8.1.1 INTRODUCTION

There are three approaches to stopping the clay formations deteriorating upon contact

with the drilling fluid:

slow down the clay-water reaction or render the clay inert (inhibiting chemicals).

limit the penetration into the shales (polymers, asphaltenes and polyglycols)

render the drilling fluid inert (invert oil emulsion systems)

In the younger shales the main destabilising mechanism is dispersion of the clay lattices

by penetration of water into the interlattice zone. Limiting water penetration in these

formations is difficult due to their rapid reaction rate. Using IOES is generally not

economic due to the large volumes required and the potential for downhole losses. The

main stabilising mechanism is the use of inhibitive chemicals.

1.1.8.1.2 CATION EXCHANGE

General

The interlayer cations, which control the dispersion of clay lattices, are exchangeable.

Many factors influence this reaction.

The replacing power of the common cations is Na+<K+<Ca++<Mg++<NH4+. The exchange

is stoichiometric and the laws of mass action hold. Increased concentration of the

replacing cation results in greater exchange. The ease of release depends not only on the

ion, but also upon the other ions filling the remainder of the exchange positions.

Replaceability varies with the nature of the anions present in the solution; Ca++ in the

hydroxyl form is more available for exchange than the sulphate variety. The pH

dramatically affects the reaction. Fixation of the exchange cations varies with the size of

ions of the same valence. For ions of equal valence, those that are the least hydrated have

5353

the greatest energy of replacement. K+ fits into the basal oxygen sheet and remains fixed.

The internal clay structure also plays an important role.

With so many influencing factors, predicting the response of a particular shale is

potentially unreliable. In exploration drilling the estimate will generally be reliant upon

experience in surrounding areas. In development drilling, cores (albeit sidewall cores) are

available and should be tested to determine the most effective solution. Recovered

cuttings cannot be used as they will have already undergone some alteration.

Chloride

Highly ionic solutions, particularly those with monovalent anions severely reduce the rate

of water imbibition by smectite clays. The most common, and most economical, is

chloride (Cl-); usually as common salt, NaCl. In offshore applications this is readily

available (and free) from the sea water (20,000 mg/l).

Calcium

The Ca++ smectite is considerably less reactive to water than the Na+ variety. Ca++

preferentially replaces Na+. Common sources of calcium are: CaCl2, Ca(OH)2 [lime] and

CaSO4,.2H2,O [gyp].

Calcium drilling fluids are more difficult to run as most common additives adversely

react with divalent ions; there are some tolerant materials available. High calcium

systems, in conjunction with high temperatures and hydro-aluminium silicates (clays),

can form a type of cement, rendering the drilling fluid irretrievably solid.

Magnesium

Mg++ reacts similarly to Ca++ . However many more additives are adversely sensitive to

Mg++.

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Potassium

A primary agent in the diagenesis of smectite to illite/muscovite. The process is normally

slow (geological time) and requires high energy (pressure and heat). However in some

cases (K++ deficient deposition environments) the reaction does progress fast enough to

be beneficial. Commonly K+ is provided by KCl.

K+ activity can be negated by high concentrations of Na+. K+ varieties of common fluid

additives, such as KOH and K2CO3, are available. When using sea water, ensure

sufficient K+ concentration to exceed that of the Na+.

Once fashionable were Potassium-Lime/Gyp systems. It was theorised that first the Ca++

would convert the reactive Na+ smectite to the low reactive type and then the slower

reacting K+ would then convert the smectite to sub-illite. Exchange chemistry indicates

that this cannot happen.

KOH has been promoted as a stabiliser for reactive clays. However, the OH- radical is the

prime clay dispersive element; therefore this reaction is dubious.

Phosphate

Complexing of the phosphate anion with the exchangeable cations can preclude cation

exchange and water imbibition. The most commonly employed forms are PO4- or P2O7-.

Bit balling additives are phosphate surfactants. Most phosphates have a temperature limit

of 65°C; though Na2HPO2 can be used up to ±200°C.

Other Compounds

Periodically other chemicals are investigated or promoted. The reactions, and any side

effects, should be thoroughly investigated before field testing. Evaluation should consider

all potentially beneficial factors.

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1.1.8.21.1.8.2 INHIBITING POLYMERS INHIBITING POLYMERS

In the more competent shales the naturally low permeability resists ingress of water,

within the time frame of drilling the section, and the shales are usually composed of the

less reactive Illite. The main destabilising mechanism is differential tectonic stress.

The drilling fluid cannot permanently protect the formation against this deterioration.

However it can mitigate the effect by providing a restraining differential pressure to hold

the failed pieces in place. To maintain this protection until casing point the fluid must

resist pressure equalisation into the shale for that length of time.

Cuttings from these formations also need protection from the annular environment. They

are subjected to considerable force and abrading action in their journey. Maintaining

them at the largest possible size facilitates easier and earlier removal at the surface. This

protection must be rapid as the cuttings are being attacked immediately they are released

from the bottom of the hole.

ENCAPSULATING POLYMERS

Coating the exposed clay edges at the wellbore wall with high molecular weight

polymers to slow down or try and repel the water is not effective. Such materials are too

large to effectively stop pressure transmission.

The limited successes reported in the field is attributed to a mechanical binding effect

from these highly adsorptive materials or to other mechanisms in the system, such as

increased pseudoplasticity.

5656

Encapsulating polymers can provide sufficient protection to the cuttings to allow them to

be transported to the surface. Application is limited to the shales that produce actual

cuttings during drilling (medium to hard). The soft shales mechanically disintegrate too

easily, and every small particle of shale will take up polymer. This consumes expensive

material for no benefit in keeping the particles together.

PAC (Poly Anionic Cellulose)

PAC is a modified CMC. It is a relatively long chain polymer that is Poly Anionically

charged.

PHPA (Partially Hydrolysed PolyAcrylate/Amide)

PHPA is a synthetic long chain copolymer based upon acrylic acid. The side chains are

highly anionic.

1.1.8.2.1 HYDROPHOBIC POLYMERS

These materials are anionic asphaltene like substances. Application is limited to high

temperature wells they can soften and bond to the borehole walls. Like encapsulating

polymers, they do not stop pore pressure penetration. Their limited success in certain

areas is attributed to a mechanical binding effect.

BLOCKING AGENTS

TAME (Thermally Activated Mud Emulsion)

Outside of invert oil emulsion systems the only available material to effectively block the

pore throats and stop pressure transmission are polyglycols.

These molecules are normally soluble in a drilling fluid at surface conditions. When the

temperature passes a critical point, the polyglycols change to an insoluble phase; this

transition is called the cloud point. The resultant micro-gels are large enough to block the

shale pore throats and stop pressure transmission.

5757

The transition temperature can be regulated with the choice of polyglycol and salinity of

the base water to match the cloud point with the formation temperature. The polymer

then penetrates the pore throat, heats up, comes out of solution and blocks further

penetration.

1.1.8.31.1.8.3 INHIBITIVE SYSTEMS INHIBITIVE SYSTEMS

1.1.8.3.1 DESIGN

Having decided to use an inhibiting system, selection then proceeds to satisfy all the

criteria to drill the well.

Selection Criteria

In addition to those already discussed other performance criteria are:

Fluid Invasion

Minimum petrophysical log interference

Minimum reservoir impact

Filter Cake Minimise differential sticking

Lubricity Minimum drilling energy loss

The drilling fluid must also satisfy some common

requirements, such as:

Environmental Non toxic and safe

Temperature Tolerant to the expected downhole & surface temperatures

Compatibility No adverse reaction with other additives

5858

Contamination Tolerant of expected contaminants

Ease of use Minimum manpower

No Lumping Maximum utilisation

Rapid mixing Fast preparation in emergency

Selection Process

Each phase is analysed. The fluid properties are investigated to determine the

performance levels required. Additives are compared against the models. The economics

of the various products are then evaluated to select the optimum fluid for the well.

1.1.8.3.2 TYPICAL FORMULATIONS

The salt polymer systems follow the same basic make-up. Typical components are:

hardness sequestrant, inhibiting salt, viscosifier, encapsulating polymer, filter cake

polymer, hydroxide, defoamer, biocide, lubricant (high angle directional only), anti-

scalant, corrosion protection, weighting material and oxygen scavenger.

Saltwater Polymer

Upper hole sections where hole stability is from type 1 and 2 shales and uncemented

formations.

Inhibiting Salt

NaCl (low concentrations)

CaCl2 (low concentrations)

Phosphate (low concentrations) for bit balling.

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Pore Fluid Isolation

Polyglycol.

Viscosifier

Bentonite

CMC Hi Vis (upper sections)

Xanthan Gum (lower critical sections)

Encapsulator

PAC (type 2 shale only)

PHPA (type 2 shale only)

Filter cake

Bentonite (uncemented formations)

Stabilised starch

CMC Lo Vis

pH

Caustic Soda (NaOH)

Salt Polymer

Type 2, 3 and 4 shales. Additives in addition, or alternate to, those listed for the

saltwater-polymer system:

Inhibiting Salt

6060

NaCl (up to saturation)

Viscosifier

Xanthan Gum

KCl Polymer

Type 5 shales. Additives in addition, or alternate to, those listed for the salt-polymer

system:

Inhibiting Salt

KCl ( 3 to 7 % for freshwater based) (10 to 15 % for sea water based)

pH Caustic Potash (KOH)

There are many individual variations depending upon the specific goals to be achieved,

the conditions prevailing and the economics of the operation. The above are purely meant

as typical guidelines.

1.1.8.3.3 ENGINEERING

The key to successfully drilling unstable ground is maintaining stable properties and

composition.

In addition the system must be adaptable to variances from the original hypotheses.

Unless permanently converted , any potentially troublesome formation will revert to

being problematic if the stabilising mechanism is diluted or removed. Most fluid designs

are based upon what will probably happen, some on what might happen, but very few

upon what will happen. Thus the engineer must be aware of changes in the formation and

its relation to the drilling fluid. If a change is observed or if the fluid is not inhibiting the

formation sufficiently he must adjust the right parameters accordingly.

6161

A key requirement for effective management of the inhibitive drilling fluid is single

function additives. Individual properties can then be adjusted without interference to the

other properties. This is essentially for maintaining overall efficiency.

Monitoring Performance

The key to proper engineering of the inhibited fluid is being able to recognise the

indicators of a problem.

Penetration rate

The penetration rate can be an indicator of increased porosity in a shale section due to

abnormal pressure.

Cuttings and Cavings

The cuttings being screened at the shakers are a primary

indicator of what is happening downhole.

Class 1 shales Poor quality cuttings.

Class 2 shales Good sized, though soft, cuttings when properly inhibited.

Class 3 shales Hard cuttings when properly inhibited.

Class 4 shales Very hard. These generally cannot be broken with the finger nail.

Class 5 shales Good firm cuttings when properly inhibited.

Shape and size Long teeth and PDC's give big cuttings, carbide buttons give small

chips, diamonds give very small cuttings. The driller is a good

reference on this subject. Long slivers indicate geopressure. Blocks

indicate stress compressive failure, slivers or flat shape tensile failure.

6262

Volume An increase in the amount of cuttings could indicate improved cutting

inhibition, deterioration of the borehole , or a slug of poorly

transported cuttings.

A decrease could indicate increased borehole inhibition, increasing

dispersion of the formation, or decreasing transport efficiency.

Hole Conditions

Tight hole and excessive torque indicate that the hole is less than gauge. This can be due

to swelling of water sensitive young clays or geopressured plastic formations.

Background Gas

In abnormally pressured formations extra gas is contained in the larger porosity.

Bottoms up lag time

Any washed out or undergauge sections will affect the circulation time.

Drilling fluid Properties

Several drilling fluid properties can give an insight into the effect of the fluid on hole

stability.

An increase in fine solids may indicate dispersion of the formation clays.

If KCl is being employed the take-up of K+ by the formation can be interpreted by

analysing plots of the K+ and Cl- concentrations . If the K+ is being consumed the plots

will diverge with an increasing Cl-. If the plots are parallel then no K+ is being taken out

of the system.

Property Control and Adjustment

6363

An inhibited drilling fluid should be designed where each major property is controlled

with a single function additive. The make up will generally be:

Viscosifier

Inhibiting Chemical

Encapsulating Polymer

Filtrate Reducing Agent

Weighting Material

Replacement volume, for new hole drilled, should be with whole, prepared fluid. This

will minimise variations to properties resulting from addition variations.

1.1.91.1.9 Invert oil emulsion systems Invert oil emulsion systems

1.1.9.11.1.9.1 INTRODUCTION INTRODUCTION

A non aqueous fluid in contact with a water sensitive clay will not have the problem of

interaction and dispersion of the lattices. An immiscible liquid will have a capillary

resistance to flow into the minute pore throats of the shale, thus resisting pore pressure

penetration. Therefore a drilling fluid based upon an oil medium can resist borehole

instability from both of these mechanisms.

1.1.9.21.1.9.2 THEORY THEORY

It is not practical to use an all oil drilling fluid. In any drilling operation there are

numerous sources of water; including released connate water. Encapsulated, high salinity

water has an osmotic interaction with the shale. This reduces the desire to imbibe water.

Thus the invert oil emulsion system (IOES) was developed.

The encapsulated water must be evenly disseminated and emulsified to resist

coalescence. The emulsifier is a surfactant (a fatty acid soap) that makes the surface of

6464

the water droplet oil wet and repellent to water. {Oil in water emulsifiers work in the

opposite way by making oil droplets water wet and repellent to oil.}

This barrier acts as a semi-permeable membrane. It is selective in allowing the passage of

water without allowing any of the dissolved salts to pass. The clays in the formations

being drilled contain interlayer water. The encapsulated water is made more saline than

the connate water. By the process of osmosis it pulls water from the formation. This

negates the desire of the newly drilled rock to 'sponge' up fluid from the drilling fluid.

IOES have a low coefficient of friction due to the natural lubricating properties of the

base oil. This can be advantageous in high angle wells. They are particularly efficient and

cost effective on multi-well platforms and sites where the fluid can be reconditioned and

reused.

IOES is not preferred on exploration wells as the oil interferes with visual hydrocarbon

spotting, gas chromatography and a number of the normally used logging parameters.

The primary disadvantages with IOES is the cost of the base oil and the environmental

impact.

1.1.9.31.1.9.3 ENGINEERING ENGINEERING

BASE OIL

A primary restriction on the use of IOES is the potential health and environmental impact

of the base oil. Diesel, the traditional media, is unacceptable due to the content of

aromatic hydrocarbons. So called 'Low Toxicity' mineral oil is also not preferred as it still

has an unacceptably high impact on the environment.

Several modified vegetable and animal (fish) oils have been developed and are marketed

under the name of 'Pseudo Oil Base Mud'. Whilst apparently acceptable within the

current legislative limits these are still oil base fluids and can have a range of impacts on

the environment.

6565

Before specifying an IOES all HSE factors must be evaluated; such as oxygen

consumption on biodegradation, the toxicity of all breakdown products, nutrient

blanketing and additive toxicity.

OIL/WATER RATIO

The desired ratio will depend upon the density, viscosity and the amount of water

expected to be absorbed. If a lot of water is drawn then the salinity of a low water content

drilling fluid would be quickly reduced - the expected water intake per circulation should

be no more than 0·5% of the water content of the drilling fluid.

Most oil systems operate comfortably in the range of oil/water ratio of 90/10 to 65/35;

though some systems can be prepared to handle ratios as high as 35/65.

EMULSIFIERS

The encapsulating barrier of the emulsifier is the main protection against water contact

with the shales. It must be strong enough the resist the differential pressure applied at the

wellbore wall. The hydroxyl ion converts the fatty acid to the emulsifying surfactant.

Lime, Ca(OH)2, is used; to be compatible with the CaCl2 salinity of the water phase.

SALINITY

Because of its higher attraction for water (activity) CaCl2 is the preferred salt.

There are two schools of thought on the concentration required to drill a hole: balanced

(Exxon promoted) and overbalanced (industry, incl. Shell, promoted) activity.

In the balanced activity system the engineer matches the desire to absorb water (activity)

of the IOES to the activity of the formation. The main problems with this concept are:

The activity is based upon measurements on the cuttings, which have already

been exposed to the oil mud and stress relieved. Their activity has been modified.

6666

Over a long section of drilling the formation may change its activity. Which

formation to balance?

In the overbalanced concept the IOES is run with a considerably higher salinity. The

objective is to create a differential force towards the wellbore. This will provide an extra

protection against any desire for the formation to imbibe fluid.

An important point to remember when making CaCl2 additions is its natural water

content, 72-77% or 95-98%, and its hygroscopic nature. Old stocks should always be

checked in the retort. The water content will affect both the oil/water ratio and the final

solution salinity.

Determining Salinity Requirements

To ensure that the IOES has a higher activity it is essential to determine the actual

activity of the formation.

Several methods of direct measurement have been proposed, however all use the already

modified cuttings.

By analysing all of the influencing factors, an activity

balance can be established.

To Formation From Formation

Hydrostatic Head of the Drilling fluid Pore Pressure

Desire from Salinity of Connate Water Desire from Salinity of Drilling Fluid

Matrix Stress Relief of Formation

The lowest IOES activity should balance or exceed the highest formation activity.

6767

VISCOSIFIER

An emulsion has a base consistency; comparable to that of dispersed, fine, solids. Amine

treated bentonite, called organophyllic clay, is the primary viscosifier for IOES. It

provides a bentonite like viscosity.

FLUID LOSS

The bentonite filter cake is supplemented with amine treated lignite and other materials

that decrease the cake permeability.

CONDITIONER

A term given to an additive (often Lecithin based) that oil wets normally water wet solids

such as barytes to disperse them in the continuous oil phase.

THINNER

A chemical strips the amine from the organophyllic clay rendering it ineffective. The

disadvantage is that any other amine treated material is also stripped and subsequent

additions of viscosifier may be affected.

WEIGHTING AGENTS

These are as per water based drilling fluids.

Note that Barytes which has been recovered by a flotation process may be coated in a

water wetting surfactant which could create problems in an IOES application.

1.1.9.41.1.9.4 MONITORING MONITORING

Apart from the normal properties it is important to ensure that the IOES has an activity

overbalance and emulsion stability.

6868

The activity balance should be regularly updated for formation pressure and salinity

changes.

The best method of evaluating the emulsion stability is by examining the filtrate from a

High Temperature High Pressure fluid loss test. The filtrate should contain no oil.

Otherwise the membrane has not been effective at this pressure overbalance. If water is

observed, emulsifier must be added to reinforce the membrane.

A quick check of the emulsion stability can be made with the Emulsion Stability Meter. It

uses an imposed voltage potential to determine the resistance to coalescing the water

droplets to pass the current. However it should only be used as an initial screening tool.

Confirmation of stability must be made with the fluid loss test.

1.1.101.1.10 Contaminants Contaminants

1.1.10.11.1.10.1 INTRODUCTION INTRODUCTION

A contaminant is an intruding element that adversely impacts upon the functions of the

drilling fluid. It could be an ion, drilled solids, temperature or even water. This Topic

deals with chemical contaminants, their effect on water based bentonite and polymer

fluids, identification tests and treatment guide-lines.

1.1.10.21.1.10.2 CHEMICAL CONTAMINANTS CHEMICAL CONTAMINANTS

SOURCES

The main chemical contaminants are:

Divalent Cations Calcium/Magnesium

Monovalent Anion Chloride

Acid Gases H2S, CO2

6969

The sources of the contaminant can be manifold and it is critical to the treatment decision

that this be identified. If it is a short term event then remedial treatment may suffice.

However, if it is likely to be a long term contamination then conversion to a more tolerant

fluid type may be required.

EFFECTS

Contaminants have varying effects on different drilling fluid materials; due to

composition and ionic variances.

7070

Flocculated bentonite will have a higher low shear viscosity and increased thixotropy.

Precipitated polymers will be taken out of solution and their influence reduced.

IDENTIFICATION

Most contamination can be deduced from the routine density and Marsh Funnel tests and

a simple pH measurement.

Solids increase the density and viscosity, water has the opposite effect. Gas drops the

density, but raises the viscosity. Cement contains lime which raises the pH while the acid

gases lower it.

In the event of formation or accidental contamination the Total Hardness test, which

identifies both Calcium and Magnesium, will suffice to differentiate it from Chloride

contamination. It is used in preference, as chlorides cannot be treated out.

7171

Figure 6.1.16: Contaminant Identification

In some case the Calcium and Magnesium need to be further differentiated as some of the

newer generation polymers are sensitive to only one. The supplier should advise on such

idiosyncrasies.

H2S can be readily differentiated from CO2 by a gas detector and its unique odour.

However care should be taken with high pH fluids as the H2S may be in solution and not

immediately detectable.

Carbonate treatment of Ca++ and Mg++ contamination can dramatically affect the

pH/Alkalinity of the drilling fluid. This is covered more fully under property testing, but

suffice it to say that alkalinity should always be tested when Carbonate ions have been

used.

1.1.10.31.1.10.3 TREATMENT TREATMENT

CALCIUM/MAGNESIUM

Short term contamination can readily be treated out with a sequestrant. The choice will

depend on availability, application, environment and the resultant effect on the fluid.

7272

Long term contamination requires a change to a tolerant drilling fluid. 'Gyp' and 'Lime'

drilling fluids are very inefficient in terms of rheology, with high friction pressure losses

and poor carrying characteristics. But their worst feature is the progressive Gel Strengths

that can develop during trips (particular at elevated bottom hole temperatures), resulting

in high surge and swab effects and excessive pump pressures to break circulation. This

can, in part, be controlled with 'thinners' (also called 'deflocculants'); though their use

should be limited because they effect the low shear part of rheology profile by reducing

interparticle attraction.

Modern polymer technology has developed products which are tolerant to high levels of

Ca++ and Mg++ whilst providing good fluid properties for efficient operation.

CHLORIDE

There is no chemical treatment to remove the Chloride ion. Unless the contamination is a

one off occurrence, the system must be converted to compatible products. Most polymers

work effectively in salt solutions up to sea water concentration. Various products are

discussed in the sections on salt polymer systems.

7373

ACID GASES

H2S can be held in solution in the safe HS- form by maintaining the fluid's pH above 9.

Remedial treatment uses sequestering ions for H2S, these are Fe++ and Zn++. Zinc

compounds (as Carbonate or Chelate) are used as a pre-treatment and for moderate levels

of contamination (<1,000 mg/l). A special form of sintered Fe2O3 (sponge) is sometimes

used; however it is a solid and creates surface processing problems.

In solution CO2 is in the bicarbonate form. Calcium is used as the sequestrant.

OTHER

Borate (B4O7--) can be found in sea water. It can affect some polymers, but most

particularly Guar Gum. Removal treatment is expensive, hence a change of polymer is

recommended.

1.1.10.41.1.10.4 TREATMENT CHEMISTRY TREATMENT CHEMISTRY

In the treatment of contaminants the objective is to remove the majority of the offending

ion, without introducing new complications. It is desirable to match the amount of

treatment and offending contaminant.

CALCIUM WITH SODA ASH (ANHYDRITE SOURCE)  

Equation Ca++ + CO3-- = CaCO3 (precipitate)

  (1g/l)   (1.5 g/l)    

Carbonate constitutes 56·6% of Soda Ash; thus 2·65 g/l is required.

SODIUM BICARBONATE  

Equation Ca++ + HCO3-- = CaCO3 (precipitate) + H+

7474

  (1g/l)   (3.05 g/l)    

Bicarbonate constitutes 72·6% of Sodium Bicarbonate: thus 4·2 g/l is required.

H2S WITH ZINC

Equation S-- + Zn++ = ZnS (precipitate)

  (1g/l)   (x g/l)    

3 gm/l will remove 500 mg/l.

H2S WITH IRON  

Equation S-- + Fe++ = FeS (precipitate)

  (1g/l)   (x g/l)    

3 gm/l will remove 200 mg/l.

1.1.111.1.11 TemperatureTemperature

1.1.11.11.1.11.1 DEGRADATION LIMITATIONS DEGRADATION LIMITATIONS

Nearly all drilling fluid additives have a temperature limitations.

7575

The polysaccharide polymers can be extended by the use of oxygen and free radical

scavengers. Potassium formate will extend long chain polysaccharides, like xanthan gum,

up to 190°C.

Note that the actual degradation characteristics of a product may vary and should be

checked with the supplier.

1.1.11.21.1.11.2 TEMPERATURE RESPONSE TEMPERATURE RESPONSE

In high temperature applications bentonite based fluids can exhibit an unusual response.

Initially the slurry will thin, as do most drilling fluids. However, with prolonged exposure

to temperatures over 175°C the surface charge and water envelope change in nature. The

fluid begins to develop a high progressive gel structure. This results in a very thick

drilling fluid on bottom that requires a very high pump pressure to re-initiate flow. The

problem can be combated by the use of deflocculants (which must be tolerant to the

temperatures as well). However care must be taken with this method as the thinned fluid

7676

may be compounded by the initial temperature thinning effect, resulting in very poor

suspension characteristics.

All viscosifying polymers thin with increasing temperature. There are two primary

aspects to the effect:

Viscosity reduction at the elevated temperatures.

Viscosity regain upon cooling.

The specific response is individual to each polymer. The temperature response curves for

both low and high shear rates (recommended 5·11 sec-1 and 511 sec-1) should be

requested from the supplier. Reduction in the Consistency Index 'K' can be compensated

by raising the concentration. But an increase in the Flow Index 'n' shows a loss of

performance potential.

Note that the temperature response of blended materials should be conducted on the final

slurry as synergistic or antagonistic effects may significantly alter the results.

1.1.11.31.1.11.3 BREAKDOWN PRODUCTS BREAKDOWN PRODUCTS

Lignosulphonate breaks down and gives off S- and SO2-- gases which are corrosive and

lower the pH of the drilling fluid rendering remaining lignosulphonate ineffectual.

7777

Deflocculating pyrophosphates convert to the strongly flocculating orthophosphates.

Most polymers simply break along the backbone to yield smaller, less effect, polymeric

chains. The natural polymers (Starch, Guar, Xanthan etc.) on breaking do not cause any

side effects. Cellulosics, and synthetic polymers, can produce shorter chain end products

that are strong deflocculants.

1.1.121.1.12 Drilled solids Drilled solids

1.1.12.11.1.12.1 INTRODUCTION INTRODUCTION

It has been said that "without drilled solids there would be no need for a drilling fluid

engineer".

To some respect this is true. A large proportion of the day to day treatments are in

response to the effects of unremovable solids and to replace volume lost via the solids

removal equipment.

The drilling process breaks the formations into small cuttings. During the journey to

surface they are subjected to various abrading forces further reducing them in size. The

larger sizes are readily separated by the shale shaker. But the finer particles are harder to

remove.

Recycling of these smaller particles in the circulating system reduces the performance of

the drilling operation, is potentially damaging to the production zone and can be a safety

risk.

1.1.12.21.1.12.2 EFFECT EFFECT

1.1.12.2.1 DRILLING FLUID

Solids incorporation in the drilling fluid raises the fluid density and viscosity.

Maintenance to a maximum limit will require dilution; increasing cost. Viscosity effects

will raise the ECD impact on the bottom of the hole.

7878

Incorporated solids provide increased surface area upon which the base liquids adsorb.

This reduces the free fluid for flow, raising the consistency of the fluid. The solids are

essentially inert and do not have the ability to provide a pseudoplastic (shear thinning)

rheology. This reduces drilling performance.

The incorporated drilled solids are generally angular, blocky shaped, particles. In the

filter cake they create porosity and permeability. Thus the cake continues to leak filtrate

to the formation. This results in a continuing build up of cake, increasing the potential for

differential sticking of the drill string.

1.1.12.2.2 DRILLING RATE

The recycled solids are good bridging particles. They restrict the flow of fluid into the

fractures made by the bit thus reducing the drilling rate.

The angular, hard, particles abrade and erode components in the circulating system. This

can cause premature failure resulting in expensive downtime, repairs and possibly the

failure of safety devices.

1.1.12.2.3 PRODUCTION POTENTIAL

The bridging effect of the incorporated drilled solids also impacts upon the permeable

production zone. Once in place the particles are very difficult to remove. The

composition of the solids is mostly silica (SiO2) and clay which are inert to all chemicals

except hydrofluoric acid (HF).

1.1.12.2.4 WEIGHTING UP POTENTIAL

The consistency of a drilling fluid is proportional to the surface area of incorporated

solids. Allowing for the effects of viscosifying additives, there is a limit to the amount of

solids that a fluid can incorporate before it is rendered unpumpable. If a kick is taken, it

may not be possible to weight up if this limit will be exceeded.

7979

1.1.12.31.1.12.3 PREVENTION PREVENTION

IN HOLE

The main preventative measure is to ensure that the cuttings are transported to the surface

with as little degradation as possible. This means minimising exposure time and

protecting against weakening.

The rheology of the drilling fluid should provide a high net cuttings velocity (Vf -Vs) and

a flat flow profile to minimise cuttings tumbling. Turbulent flow increases the amount of

inter-particulate collision, increasing degradation. A well designed fluid rheology plays a

very important role in minimising cuttings degradation.

A key element in protecting weak cuttings is a rapid coating with an isolating layer.

Highly anionic, high molecular weight polymers, such as PHPA, can quickly attach to the

clay and provide a suitable barrier.

SURFACE REMOVAL

Surface processing equipment also provide mechanical degradation forces. Rapid

removal is essential in controlling the incorporation of fine drilled solids.

Shale Shakers

The most effective solids removal equipment is the shale shaker. It can handle a wide size

variation and makes a definitive size cut.

If the cuttings are not excessively degraded the shaker is capable of removing the vast

majority of the solids. Multiple units with fine screens, and a suitable drilling fluid

design, have removed up to 85% of the drilled material; with the cut as low as 440 µm.

Hydrocyclones

These use acceleration to separate solids by mass differential. They come in various

sizes, but the most common sizes are:

8080

Desanders 8" - 12"

Desilters 4" - 6"

Because of the time needed for separation the hydrocyclone removes a varying

proportion of a range of particle sizes. The cut point is stated as where the cyclone

removes 50% of that particle size. Factors influencing the cut points are shape of particle,

density of particle, quantity of particles, rheology of the fluid, shape and length of cone,

vortex finder and discharge orifice.

The specific performance curves are available from the manufacturer.

Mud Cleaner

Where expensive, or environmentally sensitive, base liquids are used the hydrocyclone

can be used as a concentrator to allow finer screening. This reduces the volume processed

by the screen to improve separation efficiency. In oilfield terminology this has been

called a mud cleaner.

Centrifuge

The last stage in mechanically treating the drilling fluid is the decanting centrifuge. This

uses the same principles as the hydrocyclone. However more energy can be utilised and

the influencing parameters can be varied to tune separation to the solids in the system. It

is capable of removing down to about 2 µm.

A variation on the mud cleaner concept is to use a hydrocyclone as a concentrator before

centrifuging.

8181

Flocculants

Chemical flocculants increase the effective particle size and hence quantity of material

separated at each removal stage.

A common flocculant used is FeCl3. This material is a severe skin irritant.

Equipment Sequence

It is important that the removal of drilled solids is conducted in a size decreasing

sequence. The larger particles should be treated by equipment more suited to handle

them. Apart from the aspect of overloading the subsequent equipment, the finer particle

treating machines use increasing energy and thus have a higher mechanical degradation

effect.

No fluid should by-pass any stage of treatment. Topping up of tanks must be with already

treated fluid.

Solids removal equipment should not be bypassed for any reason, even lost circulation.

Lost circulation materials are cheaper than the drilling fluid and circulating system

components.

Dilution

Dilution is generally an expensive method of removing drilled solids effects. It does not

remove the solids but reduces their concentration. Until discarded with the excess volume

they are still in the system, abrading to finer and finer particles with more and more

surface area. In nearly all cases mechanical removal is cheaper.

As a rule of thumb it takes 25 m3 of dilution for every 1 m3 of solids retained in the fluid.

CURE

Solids removal with a centrifuge (or dilution if insufficient centrifuge capacity).

8282

NO CURE

Deflocculants

These are not a remedial treatment against the build up of drilled solids. They do not

remove the solids.

Deflocculants attach to the negative charges on reactive clays reducing interparticle

attraction. In a bentonite based drilling fluid, the deflocculant will preferentially coat out

on the desirable Na+ Bentonite; negating its beneficial effects.

Deflocculants remove the attraction forces that contribute to the low shear rate viscosity

which is providing beneficial carrying capacity (to minimise cuttings exposure time ).

In non bentonite based systems, the deflocculant will be ineffectual as it has no reactive

material to work on.

Deflocculants are a cosmetic cover-up of the effects of a solids build-up. They do not

remove the effect and can be likened to taking an aspirin for a bullet wound to the head.

They should only be used in emergency to get the drilling fluid to a usable state. Solids

removal should then be used to restore the desired properties.

1.1.12.41.1.12.4 MONITORING AND EVALUATION MONITORING AND EVALUATION

Each situation must be evaluated separately. A mass balance of volume drilled versus

solids removed will highlight the effectiveness of each removal stage.

The economics of solids removal equipment can be quickly evaluated by comparing the

dilution cost to maintain a specific solids content against the cost of using proper SRE.

8383

1.1.131.1.13 Drilling problems Drilling problems

1.1.13.11.1.13.1 BIT BALLING BIT BALLING

Water sensitive, young shales can form soft sticky clay when exposed to water. This

sticky clay can adhere to water wet metal. If the problem becomes severe the clay may

block the annulus, or cover the bit completely.

PREVENTION

Ensure good bit and hole cleaning.

Specify an inhibitive fluid to limit the water imbibition. Ca++, Cl- and PO4--- ions

are generally very effective.

CURE

Apply a concentrated slug of phosphate surfactant to ensure oil wetting of the

metal surfaces.

Apply an inhibitor to limit the water imbibition.

1.1.13.21.1.13.2   1.12.2 TORQUE AND DRAG 1.12.2 TORQUE AND DRAG

Torque is rotational resistance arising from contact with the wellbore. Drag is the linear

resistance. Excessive wall contact and sticky clays can increase the torque and drag;

reducing drilling efficiency

VERTICAL HOLES

In vertical holes torque and drag are usually well within tolerable levels. High values are

an indicator of a more specific problem and should be investigated to determine the

actual cause. Curing without such an investigation may mask a more serious problem.

8484

DEVIATED HOLES

In deviated holes the drill string is in more intimate contact with the wall. Over long

sections the contact may eventually require a lubricant to optimise the delivery of power.

Again, excessive build up of torque and drag is generally an indicator of a different

problem and all possible causes should be thoroughly investigated before applying

treatments with lubricants.

ADDITIVES

Several proprietary brands of lubricant are available. They are based upon blends of

mineral oils or processed vegetable and fish oils. The choice is based upon proven

performance and HSE considerations.

The use of straight diesel oil is bad practice. It is toxic, has a very low surface adsorption

potential and is rapidly emulsified in the fluid rendering it ineffectual.

 

1.1.13.31.1.13.3 1.12.3 DIFFERENTIALLY STUCK PIPE 1.12.3 DIFFERENTIALLY STUCK PIPE

The inability to move the drill string can result from a number of circumstances; many of

which have already been covered. The remaining, drilling fluid related, cause is

differential sticking.

CAUSE

Differential pressure, towards the formation, also acts on any pipe in contact with the

filter cake. A soft, thick, cake can act like a 'suction' cup and hold the pipe in place.

PREVENTION

Ensure that the minimum drilling fluid density, to safely drill the well, is

maintained.

8585

Use additives that will give a thin, tough, slick, impermeable cake under

downhole conditions.

Use fluted or spiral drill collars.

Do not let pipe remain stationary longer than absolutely necessary and never

when pumping.

CURE

Immediately reduce the pump rate and commence jarring. Do not stop pumps

entirely as the cuttings must be circulated out to avoid complicating the problem.

Spot one of the proprietary blended spotting fluids (packaged oil based fluids).

Use sufficient to cover the zone plus 10% above. A further volume is required, as

the pill should be moved 5 m up the hole every 10 minutes to ensure good

contact. Normally soaking time should be approximately 1 hour. Therefore an

extra 30 m of annular volume is needed.

The spotting fluid should be weighted to prevent an ingress of formation fluid.

Failing this an overshot with a drilling face is needed. During fishing the drilling

fluid must be highly treated to minimise new filter cake build up. High levels of

lubricant should be used to minimise friction on both overshot and drill string.

The fluid density must be kept to a minimum to ensure that the overshot is not

stuck as well.

1.1.13.41.1.13.4 1.12.4 LOST CIRCULATION 1.12.4 LOST CIRCULATION

INTRODUCTION

When the hydrostatic pressure of the fluid exceeds the invasion resistance fluid will be

lost to the formation. When the permeability channels exceed a size that the normal

drilling fluid cake or particles cannot bridge then whole fluid will be lost into the

8686

formation. This is lost circulation. The severity of the loss will dictate the criticality of

the situation and the response.

Seepage losses (less than 25% of the circulating rate) are usually treated as a routine

problem without interfering with the ongoing operation. Severe losses (above 25%) are

considered hazardous and require ongoing operations (excluding well control) to be

halted until remedial action has resolved the problem.

In certain circumstances, incurable problem with manageable risk, losses may be

untreated.

Prevention

Minimum overbalance of hydrostatic head, plus ECD.

Cure

Cut down the pump rate

Reduce the overbalance

Block the permeation channels.

CONVENTIONAL MATERIALS

Plating Materials

These are materials such as mica, cellophane flakes and paper sacks that supplement the

filter cake. This cure is often temporary as the cake can be later removed by the actions of

downhole tool and fluid.

Bridging and Blocking Materials

These are materials such as ground limestone, nut hulls and fibres that enter the

permeation channels and bridge off. These are effective in stopping losses into both

course granular formations and small fractures. The effect is generally permanent.

8787

SPECIAL TECHNIQUES

Foam

To produce a lighter hydrostatic column. The average density of a drilling foam is less

than 1·2 kPa/m.

Plugging Material

Granular bentonite swells by imbibing the formation and drilling fluid water to form a

plug of plastic material.

A 'Gunk' squeeze (DOB) is created with powdered bentonite dispersed in oil (1,100

kg/m3). The slurry is pumped into the offending zone. On contact with water the

bentonite hydrates and forms a plastic plug.

'DOB2C' is a variation on the gunk squeeze. Cement replaces 60% of the bentonite. The

resultant plug is stronger and more permanent.

Hydrational polymers (called super-absorbants) can take up to 1,000 times their own

weight of fresh water. The unhydrated grains are lost to the formation. They absorb water

from the formation and swell to occupy the volume of the absorbed water. The space or

fracture is then filled with a gel.

Floating Mud Cap

When incurable lost circulation is below a zone of high pressure a 'floating mud cap' can

be used. Lighter fluid is pumped down the drill string for drilling. In the annulus a

column of higher density fluid is maintained by continual injection into the top of the

annulus. Both fluids are lost into the thief zone, along with the drilled cuttings, but

sufficient hydrostatic head is maintained on the high pressure zone to control an influx.

8888

This method requires very careful planning and good logistics. Connections and trips are

difficult operations under these conditions. If the heavy column of drilling fluid cannot be

maintained then a kick will be taken and an underground blowout may result.

1.1.13.51.1.13.5 1.12.5 CORROSION 1.12.5 CORROSION

INTRODUCTION

Corrosion is the destruction of metal by chemical or electrochemical interaction with the

environment. In drilling the main effect of corrosion is weakening of the drill pipe

resulting in washouts or pin failure.

The major corrodants encountered are carbon dioxide (CO2), hydrogen sulphide (H2S)

and dissolved oxygen (O2). In salt based drilling fluids the corrosion potential can be

enhanced by the presence of dissociated ions. Influencing factors are the chemical

composition of the fluid, temperature, velocity, pressure and metallurgy. The specific

reactions are complex with more than one type of corrosion possible. Specific details on

the reactions and interplay should be sought from the corrosion engineers.

TREATMENT

Oxygen is the most commonly occurring corrodant in the drilling fluid. Sodium Sulphite

powder and Ammonium Bisulphite liquid are the two most common oxygen scavengers

used. Treatments are usually based upon maintaining 100 mg/l excess sulphite in the

system. Additions should be made directly at the mud pump suction so that oxygen is

removed at the point of entering the system.

Oil wetting agents lay a monomolecular layer of hydrocarbon based fluid against the

metal components to minimise water, ion and oxygen contact.

Scale (calcium, magnesium or iron carbonate) can form a precipitate layer on metal

surfaces. The layer can seal the metal from the environment, and from corrosion control

treatments. Under the layer initial corrosion establishes a galvanic system which leads to

8989

further corrosion. Organic phosphates are used to precipitate divalent ions which would

otherwise react with the carbonate to form the scale.

As previously discussed hydrogen sulphide is directly scavenged from the system.

Sulphate reducing bacteria cause sulphide corrosion in an aerobic environment. The

organisms utilise hydrogen formed by electrochemical corrosion during their growth to

reduce sulphate to H2S. Various bactericides are available. In polymer fluids these are

often required to prevent degradation of the polymers.

MONITORING

The corrosion coupon is a ring placed into a tool joint. It gives an accurate measure of the

corrosion rate taking place inside the drill string. The coupon must be accurately weighed

and visually checked.

The galvanic probe gives a continuous, and instantaneous reading, of the corrosion taking

place on two sacrificial pieces of metal (brass and iron). It gives an qualitative indication

of changes to the corrosion rate.

1.1.141.1.14 Well control Well control

Being able to control subsurface pressures is critical for the safety of the whole drilling

operation. This Topic deals only with the drilling fluid aspects of well control. Well

control procedures are not covered.

1.1.14.11.1.14.1 PREVENTION PREVENTION

Except when under-balanced drilling, the pressure exerted by the drilling fluid must be

higher than the bottom hole formation pressure.

Where abnormal pressures are present the drilling fluid density must be routinely and

frequently checked. Additions of water (or oil) at all locations on the rig must be

controlled and monitored.

9090

1.1.14.21.1.14.2 EFFECTS OF KICK TYPES EFFECTS OF KICK TYPES

SALT WATER

Dilution of additives and flocculation of bentonite are the major problems. In IOES the

water must be rapidly emulsified to prevent water wetting the weighting material which

will then drop out.

OIL

Entrained oil acts as a solid in water-based drilling fluids. In IOES it dilutes additive

concentration and density.

GAS

In IOES gas can be soluble in the hydrocarbon phase whilst under pressure. This

complicates annular pressure response during well killing as the gas comes out of

solution and rapidly expands higher in the well.

1.1.14.31.1.14.3 CURE CURE

Raise the density of the fluid to control the pore pressure and circulate out the influx. Any

detrimental impact on the drilling fluid should be treated as soon as possible.

1.1.14.41.1.14.4 PREPAREDNESS PREPAREDNESS

It is important to know the circulating volume and rate at which density can be increase

with the rig's mixing system.

1.1.14.51.1.14.5 KICK AND LOST CIRCULATION KICK AND LOST CIRCULATION

If one of the formations exposed is weak and cannot withstand the wellbore pressures

then lost circulation will occur, complicating the well killing procedure.

9191

LOSSES ABOVE KICK

The problem is to provide a variable hydrostatic head whereby the exerted pressure at the

kick zone is sufficient to kill the well and the pressure at the loss zone is insufficient to

lose drilling fluid. A tricky situation.

In severe cases, trying to circulate different density fluids around will not be successful.

The generally accepted method is to set a barytes plug over the overpressured zone. This

will provide a very heavy and impermeable barrier. The losses can then be cured before

drilling ahead

The plug is basically a slurry of barytes and water that is pumped down the drill pipe and

placed at the bottom of the wellbore. The purpose of the barytes plug is twofold:

Kill the well

Settle and mechanically plug the wellbore.

The composition of a barytes plug is:

Water   0.5 m3

     

Barytes   320 kg

     

Deflocculant Phosphate

Lignosulphonate

Lignite

Synthetic Polymer

2 kg/m3

8 kg/m3 (+ Caustic 3 kg/m3)

12 kg/m3 (+ Caustic 3 kg/m3)

2 kg/m3

9292

The barytes plug is mixed and pumped on the fly; usually with a cement unit. Once

started, pumping cannot stop until the plug is outside the drill string. Otherwise it will

bridge off and stop any circulation capability.

LOSSES BELOW KICK

This is the more difficult situation of the two. The losses must be tackled first and then

the well killed.

However the influx must be controlled from rising up the annulus. Weighted fluid must

be continually pumped into the top of the annulus to stop ingress of the kick material.

Low density drilling fluid must be continually pumped in through the drillpipe to satisfy

the losses to the thief zone thus minimising the loss of weighted fluid.

When remedial action taken to combat the lost circulation, it must be mixed separately to

the circulating fluid and then placed without stopping circulation to avoid losing control.

The major problem is being able to prepare all of the drilling fluids fast enough to

maintain control.

1.1.151.1.15 Cementing Cementing

Successful primary cementation requires an uncontaminated annulus of cement with good

bond to the pipe and borehole. Key factors for the cement slurry to achieve this are: a

consistent hole shape throughout the section and good displacement of the drilling fluid.

1.1.15.11.1.15.1 HOLE CONDITION HOLE CONDITION

Drilling fluid displacement from inconsistent washouts is difficult to achieve.

Enlarged hole sizes require higher pumping rates to achieve turbulence for good scouring

of the annulus to remove the drilling fluid and filter cake.

Excessive hole enlargement requires larger volumes of cement to be pumped. Apart from

the expense, the slurry will require conditioning to modify the thickening time. Whenever

9393

additives are used there is a possibility of an incorrect assessment of the dosage required.

Unlike faulty drilling fluids treatments, poor cement conditioning is permanent.

Proper fluid design, to produce a stable and relatively consistent hole shape, is essential.

1.1.15.21.1.15.2 DRILLING FLUID CONDITION DRILLING FLUID CONDITION

A properly designed and maintained drilling fluid should need no conditioning for either

running casing or cementing. It should already provide good suspension, have low energy

flow and be easy to displace.

1.1.15.31.1.15.3 DRILLING FLUID - CEMENT SPACERS DRILLING FLUID - CEMENT SPACERS

The key factors in designing the cement spacer are:

Avoiding contamination of either fluid.

Displacement of all drilling fluid in front of cement

Removal of any filter cake that has developed.

RHEOLOGY

The rheology of the spacer should be designed to ensure complete displacement of the

drilling fluid. The rheology should promote easy transition into turbulent flow to assist

scouring.

VOLUME

The annular height of the spacer should be sufficient to have >4 minutes of contact time.

FORMULATION

Water is the simplest spacer. It can be easily pumped in turbulence and has the minimum

contamination potential. A light cement slurry (scavenger slurry) is the next simplest

spacer. The cement grains provide some scouring effect to assist in filter cake erosion.

9494

For complicated operations the spacer may require special additives. With IOES the pipes

and formations are oil wet. Cement bonding may be compromised. A water wetting

surfactant is often added to the spacer.

For overpressure situations the length of the spacer column should be kept to a minimum

to avoid well control problems. The spacer can be weighted with salt (up to 1·2 S.G.).

Otherwise a scavenger slurry can be used to achieve sufficient spacer density.

High temperature, high pressure wells may require specially designed weighted spacers.

These should be thoroughly tested for compatibility with both fluids before usage.

1.1.15.41.1.15.4 1.14.4 CEMENT PLUGS 1.14.4 CEMENT PLUGS

Sometimes a problem during drilling (such as lost circulation, stuck pipe, kick control or

deviation correction) requires a cement plug to be placed in the hole. Problems in setting

these plugs above lower density drilling fluids, without a bridge plug, can arise from

unstable interfaces causing the fluids to intermingle thus contaminating the integrity of

the plug.

This can be avoided by spotting a high consistency pill below the intended cement plug.

A thixotropic rheology is better suited to this application as the gel strength is more able

to resist the flow tendency of the heavier cement. The pill should be prepared by adding

bentonite to the existing fluid to get maximum consistency with a pumpable fluid. For the

average polymer based drilling fluid 7% to 8% bentonite (pre-hydrated) can be added to

give the fluid needed thixotropy.

1.1.161.1.16 Drill-in, completion and well intervention fluids Drill-in, completion and well intervention fluids

1.1.16.11.1.16.1 INTRODUCTION INTRODUCTION

Once the top of the reservoir is reached there must be a change in the criteria for the

design of the fluids to be used in the well. In addition to achieving the operational

processes there is the need to protect the reservoir from impairment. Therefore the

drilling fluid is generally re-named to 'drill-in' fluid to ensure that the right mind-set is

9595

achieved. In effect the drill-in fluid should be regarded as a completion or well

intervention fluid. Therefore all fluids will be regarded within this category. Specific

criteria for the operational aspect will conform to those covered in previous chapters (i.e.:

rheology)

The design criteria remain essentially the same except that the fluid should not have a

negative impact on the reservoir production (or injection) potential.

1.1.16.21.1.16.2 PRODUCTIVITY IMPAIRMENT PRODUCTIVITY IMPAIRMENT

There are two terms used in connection with a reduction in permeability caused by the

drilling process:

Damage is defined as "a reduction in permeability in the immediate near wellbore

region".

Impairment is defined as "an irreversible reduction in permeability in the

immediate near wellbore region".

Most damage manifests itself in the near well bore area - the zone of damage is

consequently called the "skin". The resulting effect on production is termed the "skin

effect".

The mechanisms of damage are:

particles plugging the formation pore throats or fractures

drilling and completion fluids reacting with formation water to form a precipitate

emulsion from mixing oil and water and stabilising with natural or introduced

surfactants

surfactants changing the wetting characteristics (anti bit balling additives and

invert oil emulsifiers)

9696

Of these mechanisms particle plugging is by far the major contributory factor; though

emulsions and oil wetting changes from IOES fluids can affect the effective fluid

viscosity. Therefore the major attention in design is on ensuring that the plugging

mechanism does not result in irreversible permeability reduction.

1.1.16.31.1.16.3 WELLBORE FLUID DESIGN WELLBORE FLUID DESIGN

The primary design criterion in Drill-in, Completion and Well Intervention fluids is to

ensure minimum impairment of the reservoir. In most cases it will be difficult to

eliminate all material that will cause impairment. Therefore in most cases the design will

allow for a damage mechanism, via a reversible process, to initially protect the reservoir

and then allow maximum permeability regain.

1.1.16.3.1 DENSITY CONTROL

In most cases the fluid will be prepared using a brine to achieve the density required for

well control. If the required density cannot be achieved then 'acid soluble' weighting

agents are generally used. In some circumstances (high density with perforated

completions) insoluble solid weighting agents are used.

Refer to Topic 1.2.6 , DRILLING FLUID DENSITY for information on using soluble

salts as weighting agents.

1.1.16.3.2 CRYSTALLISATION TEMPERATURE

Care must be taken with brine solutions (including those with polymers added) to ensure

that they are used above the crystallisation point. Otherwise the salt can precipitate and

the salinity and density will drop and the viscosity will increase.

The crystallisation temperature is the temperature at which the brine is saturated with

respect to one of the salts that it contains. Below the crystallisation temperature, this least

soluble salt becomes insoluble and precipitates. The crystals can be either salt solids or

freshwater ice.

9797

The salt will crystallise first at the coolest location (usually the tanks). If the salt crystals

settle in the pits, the density of the brine pumped downhole will be lower. As more

crystals form, without settling, they will increase the brine viscosity. Eventually the

viscosity can become so high that the brine appears to be frozen solid. It cannot be

pumped and the lines are plugged. In deep offshore wells this cooling point could be in

the riser; with the disastrous consequences of a 'frozen' annulus.

First Crystal To Appear (FCTA): This is the temperature at which visible crystals

start to form. It appears at the first inflexion in the cooling curve. It will include

some super-cooling effect.

True Crystallisation Temperature (TCT): This is the maximum temperature

reached following the super-cooling minimum. It is the FCTA if no super-

cooling takes place.

Last Crystal To Dissolve (LCTD): This is the temperature at which crystals

disappear, or the inflexion point in the heating curve.

TCT is the best measure of the crystallisation temperature of a brine. The test procedure

defined in API Recommended Practices 13J should be used.

For treated brines both the raw salt solution and the final mix should be tested as

additives can have a significant effect. For example Xanthan Gum and Starch are

crystallisation temperature suppressants.

The crystallisation temperature can be altered by changing the brine composition. As a

rule the lower the TCT the higher the price. Therefore, selecting a brine with an

excessively low crystallisation temperature can be very costly. You should specify a TCT

a few degrees below the lowest expected temperature.

1.1.16.3.3 FORMATION COMPATIBILITY.

There are three areas of concern with respect to compatibility: rock, water and

hydrocarbons.

9898

Rock

The primary concern is whether the fluid will cause swelling/dispersion of the formation

clays in the pore spaces.

Normally providing some salinity will cure this problem. This is usually achieved by

using 3% NH4Cl or 2% KCl. However, in some cases, a higher salinity can also

destabilise the formation clays. It is generally difficult to assess whether formation clays

will be affected by a fluid without extensive core flush testing.

However as a general rule, if the same ionic character as the original formation water can

be maintained then the clays should remain in equilibrium. Hence some areas now use

'Dehydration Water' to formulate Drill-in and CWI Fluids.

Water

The chief concern is the formation of precipitates, or scales. The most common scales are

calcium and iron carbonates; calcium, barium and strontium sulphates; sodium chloride;

iron sulphide; and silicates. Scale can be formed due to:

mixing incompatible waters (divalent cations and anions react together)

solubility change with temperature

solubility change with temperature and pressure.

For example: certain saturated CaBr2/CaCl2 brines can cause NaCl to precipitate from

saturated NaCl formation water. A 60°C TCT brine will give strong precipitation whilst a

-37°C brine will have no reaction.

Compatibility checks on all waters should always be confirmed by testing at downhole

conditions.

9999

Hydrocarbons

The chief concern is the formation of emulsions or the destabilisation of heavy crude

components that precipitate as sludge. Generally low to moderate salinity brines will not

be problematic. It is only the heavy, fully saturated brines that will cause problems;

particularly those with a very high or very low pH.

Surfactants added to the system may exacerbate the problem.

Compatibility testing with core flushing should be carried out.

1.1.16.3.4 FLUID/SOLID INVASION CONTROL.

Large overbalance, high permeable streaks and long perforated or open-hole sections can

cause substantial loss of fluid to the formation. Such losses are expensive and may

increase production impairment potential.

To minimise the potential for production impairment many wells are deliberately

'damaged' with materials that will naturally disappear or can be removed. These materials

can be bridging agents (sized particulates) viscosifiers or cross-linked polymers.

Bridging Materials (including lost circulation materials)

There are currently three basic options for bridging : sized salt, ground CaCO3 and oil

soluble resin.

Sized salt is the basis of the Thixsal and Bridgsal systems. It requires a saturated brine

base. The major advantage of the system is that the solute for the bridging agent is water.

The disadvantages are that the base brine density is high and not suitable for depleted

reservoir applications, the wash water solution can cause formation damage and the

dissolving process can be slow (using rig time or delaying production).

Ground CaCO3 is the most common bridging material used, especially in the case of

major fluid losses. The advantages are that it is cheap and the dissolving action with acid

100100

is vigorous promoting easy removal. The disadvantages are that the acid solution is

dangerous and corrosive.

Oil soluble resin is currently not used outside of some limited applications in stimulation

as it is not always fully oil soluble when used in water based systems.

Particle size must be chosen such that the smallest grain will be > 33% of the largest pore

throat size. This is normally selected after examining cores and scanning electron

microscope photos.

The filter cake formed by the bridging agents, if maintained externally may not be robust

enough to survive the activities being conducted in the well. Therefore it is often

supplemented with a binding agent such as starch. This is selected because it is generally

not damaging in its own right and is fully acid soluble.

Viscosifiers

High filtrate viscosities can damage the effective permeability of the formation

(increasing µ to decrease Q). It is essential to use fully acid soluble polymers such as

HEC and Biopolymer (Xanthan Gum).

Viscosifiers will also be required when using bridging particulates (albeit at a lower

concentration). The key factor in selecting the material is high quality pure material that

is degradable under the conditions of use. For example: HEC comes in many grades;

some with high concentrations of acid insoluble impurities. Xanthan Gum is not readily

acid degradable below 65°C.

Crossed Linked Polymers

These are rarely used in working fluids except during hydraulic fracturing due to the

difficulty to control the process without affecting a circulating fluid.

101101

1.1.16.3.5 CORROSION

The electrically conductive nature of brines provides an environment favourable for the

corrosion of metal to occur. Given that it is not practical to stop corrosion the aim is to

reduce it to an acceptable level. For temporary fluids (CWIF) this is generally set as <10

kg/m2/yr using a corrosion coupon test. For packer fluids this must be lower due to the

prolonged exposure.

For most brine based systems the key agent for corrosion is oxygen. The solubility of

oxygen decreases as the saturation point of the salt is approached. Even though a brine

may initially contain oxygen, if it is not replenished it will soon deplete as a result of the

corrosion process. Therefore oxygen scavengers are not used. In brines to be circulated

ammonium bisulphite is generally used to scavenge the oxygen.

Film forming amine corrosion inhibitors are not recommended as they are also adsorbing

on silica and silicates and may cause impairment. Organophosphate inhibitors are also

not used as they often give incomplete coverage and can result in galvanic cell corrosion.

Very dense bromide brines have a very low pH which means that they can cause leaching

corrosion (preferentially dissolving grains in the steel).

Bacterial growth can cause acid conditions to develop. Additions of high shock,

degradable biocides are sometimes used.

1.1.16.41.1.16.4 WELLBORE FLUID PREPARATION WELLBORE FLUID PREPARATION

Despite all of the best planning and pre-testing, poor preparation of the fluids to be used

in the reservoir section is still the major source of production impairment.

SOLIDS

Solids, other than those deliberately added, can be picked up from the drilling process,

dirty tanks, the drill water supply or even airborne sources.

102102

POLYMERS

Non-completion grade HEC contains high concentrations of partially- or un-reacted

cellulose material that can block pore throats. This cellulose material is not acid soluble.

HEC and Xanthan which is not fully hydrated can have minute polymer 'lumps' which

subsequently hydrate in place causing blockage and hence impairment. This polymer

blockage is often difficult to access with acid stimulation.

FILTRATION

Both HEC and Xanthan, when fully hydrated will pass through a 2µm filter cell.

Therefore to ensure that no damaging materials have been included the fluid should be

filtered to less than the pore through size before adding the bridging agent.

To ensure that fluid will readily pass through the filters without excessive blocking the

solution should be tested with the API fluid loss test. Both polymers will pass through the

Watman 50 filter paper.

1.1.16.51.1.16.5 DAMAGE/IMPAIRMENT REMOVALDAMAGE/IMPAIRMENT REMOVAL

The key factor is to ensure that all of the "damaging" material is removed to restore

original formation permeability. This is more easily said than done.

In carbonate formations acidising the matrix can release the bridging solids. It is

essential however that the acid solution is not too strong. Otherwise it will

dissolve the first point of contact, establish a path to the permeable formation and

be "lost" before it can remove all of the cake. Too often a report states "Got good

losses immediately upon contacting with acid". This usually means that some

cake is still there to impair production.

The acid wash treatment should be lower strength, at or near balance to the

reservoir pressure and should preferably be viscosified to resist seepage into the

formation.

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Inert solids are difficult to remove. Surging and jetting can be tried, though

success is usually very low.

Emulsion blocks can be treated with a demulsifier but success is very low.

Surfactants can restore the wetting characteristics but success is very low.

1.1.171.1.17 AppendixAppendix

1.1.17.11.1.17.1 Appendix (1) Terminology and symbols Appendix (1) Terminology and symbols

The drilling industry uses technology from various sources; internal and external.

Consequently different symbols often depict the same data unit or the same symbols

represents different data. This can lead to confusion for the uninitiated. For example 'd' is

sometimes used to denote depth. However, in rock mechanics 'z' is used for depth. In

engineering 'd' is used to denote diameter.

Standard drilling fluid symbols and terminology have been used in this Part - the ones

most commonly used. These may differ from those that you are familiar with.

Standard Units

All working units are 'standard Shell' oilfield SI. Alternate units are shown in brackets

where appropriate. Pressure is in Pascals (Pa).

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Table 6.1.16: Symbols used

1.2 Cement

 

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1.2.11.2.1 Introduction Introduction

GENERAL

Well cementing in its simplest form can be described as the placement of a material that

sets to form a solid mass which has supporting and sealing properties.

Annually the Group, excluding North America and Canada, spends approximately $600

million on drilling and workover related activities. Figure 6.2.1 shows a generalised

distribution of this expenditure.

In 1994 some $140 million was spent on drilling fluids and cementing; with about 12%

being spent on cement and cementing additives. The actual expenditure varies amongst

Operating Units but averages some 3-6% of the overall drilling budget. However this

seemingly small portion plays a vital role in well integrity.

Figure 6.2.1: 1994 Group Drilling Expenditure breakdown

A poor cementation can significantly impact on subsequent well performance and return

on investment. In comparison to the initial expenditure, a poor cement job can result in

very high remedial costs. For example, failure to achieve good zonal isolation in primary

cementing (the initial cementing of casing) costs the group millions of dollars each year

in well repairs and lost production.

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To achieve a successful cementation the Well Engineer must have a working knowledge

of the following:

Cement types .

Cement slurry characteristics .

Cement hydration process .

The effects of pressure and temperature on cement hydration.

The effect of additives .

Contaminants and their effects.

Cement testing procedures and terminology .

Wellbore fluid displacement and mud cake removal .

Primary and secondary cementing techniques.

Evaluation procedures.

REASONS FOR CEMENTING

Cementing jobs are carried out in oil wells for a number of reasons, including:

Well tubular support: To provide support for casing/liner strings to prevent

movement.

Well bore/tubular collapse: To resist plastic/brittle deformation of the

surrounding formation which may impact upon well tubulars and cause their

collapse.

Zonal isolation: To provide a pressure (to Gas) tight seal between different zones

(formation-formation or formation-surface). Includes sealing perforations to

control water production or prior to a workover.

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Corrosion protection: To isolate metal tubulars from corrosive gases and liquids

contained in the formations.

Kick-off plugs: To fill the hole with a material that is harder than the surrounding

formation to encourage the drill string to deviate from the original borehole

trajectory.

Lost circulation cures: A material that will permanently seal leakage paths into

the formation.

Well abandonment: To isolate all open hole sections from the surface.

PRIMARY CEMENTATION

Primary cementing covers all operations to fix a casing and/or liner string in a newly

drilled wellbore. The cement slurry is placed in the annulus between the pipe and the wall

of the open hole. In this placement the cement has to displace the annular contents,

usually drilling fluid, as completely as possible to permit adequate bonding to pipe and

formation as well as developing its sealing properties.

SECONDARY CEMENTATION

Secondary cementation covers all applications other than primary cementing; including

the repair of an unsuccessful primary cementation. Cement is either injected under

pressure (squeeze job) or placed into the required position (plug job).

A SUCCESSFUL CEMENTATION

The key to successful primary and secondary cementations is proper 'up-front

engineering' in the design stage and close, involved and experienced supervision of the

execution phase. Factors that can positively affect the success of a cementation include:

Adequate and timely testing of slurries using field sampled materials and water.

Proper blending of cement and additives.

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High energy, recirculating mixing.

The use of centralises and/or scratchers.

Reciprocating or rotation of the casing/liner string during displacement.

Proper drilling fluid properties.

Adequate displacement rate.

The role of the Well Engineer and the Drilling Chemist is to focus on fit-for-purpose

specifications in a partnership with the Cementing Contractor who concentrates on the

detailed design and execution aspects.

1.2.21.2.2 Cement - the product Cement - the product

1.2.2.11.2.2.1 THE CHOICE OF CEMENT THE CHOICE OF CEMENT

The requirement is to have a material which is pumpable but which sets and hardens after

placement. Although there are a number of chemicals available, e.g. epoxy, high load

polymers, elastomers, cement has some distinct advantages:

It is a 'Fit-For Purpose' Hydraulic Material that hardens to a sufficient

compressive strength and low permeability for most well applications.

There is an abundant supply readily available world-wide.

Price, being a commodity product cement is cheaper than any alternative

material.

Experience in manufacturing, preparation and placement technology is mature.

Additives are available to modify its performance to most specifications.

As with every material, cement also has its limitations:

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Cement has a variable composition and therefore can have a variable

performance.

It shrinks during setting which can compromise it bonding properties.

It is susceptible to chemical contamination which affect short and long term

performance.

The hydration process (Topic, Cement hydration) is susceptible to the physical

conditions present in the well.

It is expensive to manufacture to individual specifications

1.2.2.21.2.2.2 CEMENT MANUFACTURE CEMENT MANUFACTURE

All classes of cement are prepared in essentially the same way and made up of the same

ingredients, only in different proportions. The basic process is:

The cement is prepared by kiln-burning limestone with clay to form 'clinker'.

Average kiln temperature is 1,300°C to 1,500°C.

Iron and alumina may be added if the clay source is deficient in these

ions.

Cooling of the clinker is done in two stages: slow cooling to 1,250°C followed by

rapid cooling at 18-20°C/min

Cooling too slowly results in a cement which is not hydraulically active.

Cooling too fast results in a cement with poor long term strength.

Gypsum is dry blended during grinding of the Clinker.

This is to prevent 'Flash' setting (Topic, FALSE SET.

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The mill must be cool at this stage to prevent the gypsum dehydrating to

Anhydrite as this can result in 'False' setting.

Storage in airtight silos.

Cement is hygroscopic and sensitive to moisture and CO2.

Storage in hot regions can result in dehydration of Gypsum to

Anhydrite.

1.2.2.31.2.2.3 CEMENT CHEMISTRY ABBREVIATIONS CEMENT CHEMISTRY ABBREVIATIONS

A set of abbreviations is used when discussing cement chemistry, composition and

properties.

Composition Elements

C = CaO F = Fe2O3 N = Na2O P = P2O5

A = Al2O3 f = FeO M = MgO K = K2O

S = SiO2 H = H2O L = Li2O T = TiO2

Hydration Compounds (Topic, Cement hydration)

C2S = 2CaO.SiO2 C3A = 3CaO.Al2O3

C3S = 3CaO.SiO2 C4AF = 4CaO.Al2O3.Fe2O3

Sulphate Resistance

Sulphates can react with cement decreasing its long term strength and increasing

porosity.

MSR = Moderate sulphate resistance

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HSR = High sulphate resistance.

Bearden Units of Consistency (Bc.)

No direct correlation to other rheology measurements. Used to evaluate slurry

pumpability during displacement and initial setting.

Concentration

BWOC = By Weight Of Cement

BWOW = By Weight Of Water.

1.2.2.41.2.2.4 CEMENT COMPOSITION CEMENT COMPOSITION

Portland cement contains four basic components, each contributing in different ways to

the properties of a slurry and/or the set cement.

Small changes in the concentration may significantly affect the setting behaviour of a

cement. Individual testing of all cement batches, with field sampled material, is a

prerequisite to avoid unexpected setting characteristics.

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It is possible to change the properties of the cement by changing the ratio of the basic

components, the process temperature, the rate of cooling or by adjusting the grinding of

the cement clinker to yield coarser or finer grains.

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Figure 6.2.2: Typical Class G cement setting characteristics

This is done as follows:

High Early Strength (Most Oilfield Cements).

Increasing the C3S Content.

Grinding Finer.

Better Retardation (HPHT Applications).

Reducing C3S and C3A Content.

Grinding Coarser.

Low Heat of Hydration (Permafrost Applications)

Reducing C3S and C3A Content.

Resistance to Sulphate Attack (Most Oilfield Cements).

Reducing the C3A Content.

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1.2.2.51.2.2.5 CEMENT GRADES CEMENT GRADES

The American Petroleum Institute (API) has designated eight classes of oil well cement

(reference API Standards 10 "Specification for Oil-Well Cements and Cement

Additives"). These are shown in Table 6.2.2.

Most oilfield cements are API "Portland" cement Class G. It is primarily intended for use

from surface to 2,500m; covering the range of typical temperatures and pressures

encountered.

Typical properties of API Class G Portland cement are (note

that a "sack" has been made equal to one cubic foot):

Specific

Gravity3·15

Bulk Volume 1·47 kg/l 94 lbm/ft3

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Water

Requirement18·9 l/sack 5.00 gal/sack

Slurry

Weight1·89 kg/l 15.8 lbm/gal

Slurry

Volume32·56 l/sack 1.15 ft3/sack

Class H is identical in composition but has a coarser grind.

During the manufacture of classes G and H no additives can be included. Only calcium

sulphate (gypsum) and water may be added to the clinker. Glycols and acetates which

improve grinding efficiency cannot be used; these interfere with other cement slurry

additive performance.

Both classes G and H are available as MSR or HSR.

API classes D, E and F contain a retarding additive and therefore will exhibit adequate

thickening time when used in the correct temperature range. Be aware that these additives

may be incompatible with other desired additives (e.g. for fluid loss control). The general

purpose class G and H cements are preferred as the properties can be adjusted within

wide margins to suit a range of applications.

Oil-well cement usually represents some 3% - 4% of the total capacity of a manufacturer.

Coupled with the much more stringent specification and quality criteria, it usually

commands a higher price. It is recommended to obtain oil-well cement from a reputable

manufacturer who has been API certified; though this is not an absolute guarantee of

consistent quality.

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1.2.31.2.3 Cement hydration Cement hydration

The exact mechanisms in the hydration of cement are not fully understood. A general

outline, however, can be given. 

1.2.3.11.2.3.1 SINGLE PHASE HYDRATION SINGLE PHASE HYDRATION

SILICATE PHASES (C2S & C3S).

Form C.S.H. (C3S2H3) 'Gel'; ~70% of fully hydrated Portland cement. Ultimately

the principle binder of hardened cement.

C3S is responsible for the beginning of set and early strength development.

C2S is responsible for the final strength.

There are five distinct stages in the setting process of the silicate phase:

ALUMINATE PHASES (C3A & C4AF).

Rapidly hydrate.

Predominantly influential on rheology and early strength development.

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Rate controlled by the addition of gypsum which forms the needle like mineral

'Ettringite' which slows down the hydration rate.

1.2.3.21.2.3.2 COMPOUND SYSTEM HYDRATION COMPOUND SYSTEM HYDRATION

However the actual hydration process of Portland cement is a sequence of overlapping

chemical reactions leading to continuous thickening and hardening.

The C2S model is generally used to represent this process; however the phases influence

each other and should be considered.

The hydration of C3A is modified by the presence of hydrating C3S.

The clinker material is not pure and trace elements can catalyse reactions.

The hydration rate and nature, stability and morphology of the hydration products

are strongly affected by temperature. Elevated temperature (>40°C) accelerates

initial hydration; but may decrease the ultimate hydration and compressive

strength.

Particle size distribution affects the hydration rate, initial setting time and final

strength.

Sulphates can react with the set cement and reduce strength and increase

porosity.

1.2.3.31.2.3.3 THE HYDRATION PROCESS & HEAT OF REACTION THE HYDRATION PROCESS & HEAT OF REACTION

When cement is mixed with water two distinct peaks of heat liberation can be

distinguished. Each of these peaks results from an important phase in the hydration

process. This feature is useful in laboratory studies to identify the onset and completion

of cement setting.

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The first peak occurs almost immediately after the mixing, in the Pre-induction stage. It is

caused by an exothermic reaction between C3A, gypsum and water. The surface of the

C3A grains is partly hydrated and dissolving gypsum moves towards this hydration layer.

A thin C.S.H. gel layer forms at the surface of the C3A and C4AF grains. The slurry then

enters an apparent 'dormant' period, the Induction stage. During this period the slurry

remains liquid and it appears that all reactions have stopped.

Figure 6.2.3.: Cement Hydration Terminology

However the reaction within the hydration layer continues and after a given time, the

hydration layer bursts open, the Acceleration stage. Fibrils of recrystallising material

grow rapidly from the cement grains. This recrystallisation process causes a second peak

of heat liberation. The fibrils initially interfere with each other causing an increase in gel

strength. Ultimately they connect and form the basic cement structure and give rise to the

early strength development.

The reactions now slow down, the Deceleration stage, but the cement strength continues

to build up. The reactions continue on for some time, albeit very slowly, the Diffusion

stage, during which the ultimate strength is developed.

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Initial hydration may be adversely affected if the cement has been exposed to a humid

atmosphere.

A sound mixing/shearing of the initial slurry will give rise to a more regular initial

hydration and therefore to a better final cement structure.

The length of the dormant period and therefore the final setting time of the cement is

determined by the slurry temperature and can be adjusted by a number of accelerating or

retarding additives.

Figure 6.2.4: Thermogram of Setting Portland Cement

1.2.3.41.2.3.4 FLASH SET (OR QUICK SET) FLASH SET (OR QUICK SET)

When Portland cement clinker, without sufficient gypsum, is hydrated the C3A rapidly

reacts, the temperature increases and an irreversible 'Stiffening' occurs. 

1.2.3.51.2.3.5 FALSE SET FALSE SET

During grinding, natural calcium sulphate in the Clinker is dehydrated to Anhydrite

which has a higher solubility. Consequently, in the slurry secondary Gypsum

precipitation can occur. This gives rise to strong thixotropy, or very high Gel Strengths.

120120

This can appear, due to a surface pump pressure increase, as a Flash Set. However this

Gel is reversible upon strong agitation.

1.2.3.61.2.3.6 WATER/CEMENT RATIO WATER/CEMENT RATIO

The minimum required amount of mix water for cement hydration is some 0·150

m3/1,000 kg of cement. This, however, leads to a very viscous, unpumpable, slurry. In oil

well cementing ratios between 0·38 m3/1,000 kg and 0·5 m3/1,000 kg are routinely used.

Optimum water/cement ratios are defined for the various types of cement (reference

Contractor Cementing tables).

1.2.41.2.4 Cement types and additives Cement types and additives

The properties of regular Portland cement don't always conform to the job at hand.

Temperatures from Ambient to >350°C.

Pressure from Atmospheric to > 200 MPa.

Pumping Times from Minutes to Hours.

Additives are used to modify cement properties and can be categorised as:

Density Control .

Dispersants or Friction Reducers .

Accelerators: increase hydration rate, decrease pumping time .

Retarders: decrease hydration rate, increase pumping time .

Fluid Loss Control: reduce aqueous phase losses .

Lost Circulation Control .

Speciality Additives .

Speciality Application .

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1.2.4.11.2.4.1 DENSITY CONTROL DENSITY CONTROL

During placement well control must be maintained. The cement density may need to be

adjusted to ensure that the bottom hole pressure remains within finite limits.

A cement slurry density can be increased with heavy-weight additives (such as barytes or

hematite) or saline mix water or by using less mix water (though this may have other

detrimental effects).

A cement slurry density can be reduced by 'extending'. This means adding a material to

reduce the grain density and at the same time enabling a higher water/cement ratio to be

used.

Figure 6.2.5: Density Range for Various Cements and Additives

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POZZOLANIC CEMENTS

Pozzolan was originally a volcanic ash named after the place in Italy where it is found in

large quantities. The term is now used for a group of materials that react with lime to

form cement like compounds; such as blast furnace 'fly-ash'. Pozzolans are mostly

blended in a 1:1 ratio with API Class B oil-well cement. They have been extensively used

in various cementing industries.

Pozzolan cement blends have a grain density of 2,820 kg/m3 and a bulk density of 1,185

kg/m3.

Pozzolan cement slurries have gradients in the range 15·5 to 16·0 kPa/m (13·2 to 13·6

ppg) but can be made into stable slurries in the range 14·5 to 17·0 kPa/m (12·3 to 14·7

ppg), using additives.

An additional advantage of Pozzolans is a reduction in natural cement strength

retrogression. When Portland cement hydrates it releases some 20%mass lime. This

contributes nothing to the strength of the cement, but being soluble it eventually leads to

a weakening of the matrix. Pozzolan combines with the lime increasing the strength and

reducing the permeability of the cement.

The main attraction of natural Pozzolan is its consistent quality. The quality of fly-ash

can vary significantly between sources. It also differs from volcanic ash in that it also

contains iron oxides (Si, Al and Fe). The use of fly-ash should be accompanied by quality

control testing to achieve satisfactory results.

Fly-ash in Portland cement is usually blended in a 50/50 by volume ratio in admixture

with 2-4%BWOC of bentonite to improve stability and reduce 'free water'.

FLY-ASH CEMENTS

Fly ash and lime can be prepared and need no addition of Portland cement. Their reaction

is slower and the mixture is therefore suited to high temperatures.

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SLAG MIX

'Pozzolan' or 'Fly Ash' is the cement material used in the preparation of 'Slag Mix' or 'S-

Mix' cements. In this system drilling fluid is used as the mix water. Because of the highly

variable nature of drilling fluids extensive testing is usually required to ensure a good

quality job. It is essential that the drilling fluid sampled for testing is not used again.

1.2.4.21.2.4.2 DISPERSANTS OR FRICTION REDUCERS DISPERSANTS OR FRICTION REDUCERS

For maximum displacement efficiency (i.e. mud removal) the cement should be as thin as

possible and be displaced at maximum velocity. Well cement slurries are highly

concentrated suspensions of solids; up to 70%volume. There is an electrostatic interaction

between the C.S.H. layers around the grains; similar to the interaction with bentonite

particles. A dispersant aims to reduce this viscosity effect in the cement slurry, thereby

promoting turbulent flow at lower pump rates. The need for a well dispersed low viscous

cement slurry becomes more and more critical with deeper, slimmer, hotter wells.

Organic acids, in particular polysulphonates, are the most common dispersants. Modified

polysaccharide polymers are also effective dispersants.

Dispersants also retard hydration and reduce thixotropic properties. The combination of a

dispersant with a fluid loss reduction additive exhibits strong synergy.

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Excessive use of dispersants can lead to settling of the cement particles causing

segregation and non-uniform slurry densities This is particularly important with batch

mixed job that are not adequately agitated before pumping.

1.2.4.31.2.4.3 ACCELERATORS ACCELERATORS

Accelerators are materials that shorten the thickening time of the cement slurry and

accelerate strength development in situations where low temperatures would lead to

excessive waiting on cement times. They are often used to offset the hydration delaying

effect of other additives.

They are usually inorganic salts. There is an efficiency series of:

Ca++ > Mg++ > Li+ > Na+ > H2O; OH- > Cl- > Br- > NO3- > SO4

-- = H2O

CaCl2 is the most cost effective accelerator. In dosages of 0 to 5% BWOW (2 - 4%

BWOC) it will accelerate the setting of a slurry by up to 30%. Concentrations of CaCl2

higher over 5% are not recommended as the reaction becomes very unpredictable.

125125

CaCl2 dissolution is an exothermic reaction. Therefore to avoid any side effects caused by

a high mix water temperature it should be added to the mix water several hours in

advance.

NaCl is also a commonly used accelerator. Up to 10% BWOW it will accelerate the

setting by some 20 %. Between 10 and 18% it is neutral. Over 18% it is a retarder.

Magnesium salts are also very powerful accelerators. Aluminium sulphate is also a very

effective accelerator. However its thixotropic effect makes it less attractive for most

applications as it will adversely affect displacement and give unacceptably high ECDs.

The actions by which accelerators work are very complex and not fully understood.

Predominantly they accelerate the hydration of C3S. CaCl2 changes the C.S.H. gel

structure to make it more permeable and allow more diffusion of water to the underlying

clinker. Chloride ions diffused into the C.S.H. gel cause excessive internal pressures

resulting in an earlier rupturing of the membrane. CaCl2 Increases the rate of heat

generation during the first few hours which accelerates the chemical reactions.

126126

Magnesium salts are also very powerful accelerators. Aluminium sulphate is also a very

effective accelerator. However its thixotropic effect makes it less attractive for most

applications as it will adversely affect displacement and give unacceptably high ECDs.

The actions by which accelerators work are very complex and not fully understood.

Predominantly they accelerate the hydration of C3S. CaCl2 changes the C.S.H. gel

structure to make it more permeable and allow more diffusion of water to the underlying

clinker. Chloride ions diffused into the C.S.H. gel cause excessive internal pressures

resulting in an earlier rupturing of the membrane. CaCl2 Increases the rate of heat

generation during the first few hours which accelerates the chemical reactions.

Figure 6.2.6: Action of Accelerators and Retarders on Cement Hydration.

1.2.4.41.2.4.4 RETARDERS RETARDERS

These products are applied to achieve the opposite effect of accelerators, i.e. increasing

the thickening time, at the temperature and pressure, to allow the slurry to be placed

before initial set.

Most retarders are organic acids, salts or polymers. The most common are Na- and Ca-

lignosulphonic acids. The active components are the saccharide carbohydrates and

127127

aldonic acids which are naturally present in the raw material. Refined lignosulphonate, as

used in drilling fluids, are deficient in these compounds and therefore should not be used.

Lignosulphonates are most effective in the range of 0·1 - 1·5% BWOC.

Figure 6.2.7: Impact of Retarder Concentrations.

Cellulose derivatives such as CMHEC are also effective retarders; as are

organophosphates, such alkylene phosphonic acid and NaCl at concentrations >18%

BWOW.

Most retarders are characterised by an exponential response in the thickening time of the

cement slurry, i.e. at low dosage rates the effect is rather small but it increases

exponentially with further chemical addition (See Figure 6.2.7). Therefore they should

only be used over a certain concentration range.

The retarding effect is temperature dependent and most commercial products can be used

only in a given temperature range.

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A common, beneficial, side-effect of a retarder is the reduction of slurry viscosity and

yield point due to its dispersive action.

1.2.4.51.2.4.5 FLUID LOSS CONTROL FLUID LOSS CONTROL

Neat cement slurries exhibit a very high, essentially uncontrolled, fluid loss against a

permeable media. For most cementations some measure of fluid loss control is highly

129129

desirable to prevent excessive slurry dehydration. An API fluid loss of 150 to 300 cm3

(Spec. 10A) is recommended to provide adequate control for primary cementations.

Most of the fluid loss reducers in use are either a cellulose derivative, a polymer or a

filter cake building solid.

These additives will generally act as retarders. They also tend to increase slurry

consistency, which is usually countered by adding some dispersant. Like retarders, fluid

loss control additives exhibit a temperature dependent action within a specific envelope.

Hydroxyethylcellulose derivatives (such as CMHEC) are common fluid loss reducers.

The HEC polymer molecules tie up the water and prevent it from freely leaking off. This

loss of free water results in a slurry viscosity increase.

Other types of fluid loss reducers, such as Diacel LWL, build up a filter cake. It should be

emphasised that this type of products will only work if the slurry is sufficiently dispersed

to provide the small particles required for a good filter cake.

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FREE WATER AND PARTICLE SETTLING

Non-homogeneous cement columns are unacceptable, particularly when the wellbore is

highly deviated or horizontal. Ultimate cement sheath integrity and strength may be

severely compromised. Anti-settling agents are used to provide (or restore with the use of

dispersants) sufficient viscosity to maintain slurry consistency.

Bentonite and HEC derivatives are most commonly used to restore this viscosity.

For deviated and horizontal wells it is important to test this phenomena at the actual well

angle.

131131

1.2.4.61.2.4.6 LOST CIRCULATION MATERIALS LOST CIRCULATION MATERIALS

Lost circulation is a potential problem when drilling through permeable, well fractured,

faulted or cavernous formations. To restore circulation, or reduce the chance of creating

losses during cementation, lost circulation materials may be added to the cement. A

tabulation of available LCM is shown in Table 6.2.9 below.

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1.2.4.71.2.4.7 SPECIALITY ADDITIVES SPECIALITY ADDITIVES

EXPANDING AND BOND IMPROVEMENT

Ordinary Portland cement shrinks about 4% upon setting. This can reduce bottom hole

pressure below the static slurry and compromise the cement bond. These agents target

reducing shrinkage.

Chemical or crystal growth expanders

Calcium sulphate hemi-hydrate and calcined magnesium oxides are the most prominent

compounds. They produce their expanding effect well after the cement has set.

Gas-generating expanders

Gas (hydrogen) can be generated in-situ during the gelling stage of the cement slurry.

Expansion takes place as a consequence of the reduced hydrostatic pressure as the cement

column is progressively carried by the gel structure. The most common material used for

this purpose is aluminium powder. The safety aspects of hydrogen however should not be

overlooked.

 

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STRENGTH RETROGRESSION

An addition of 35% BWOC of silica flour is recommended to combat strength

retrogression in high temperature wells.

ANTI-FOAM

High energy cement preparation introduces a considerable amount of air into the slurry.

This can affect density and cause suction and cavitation problems at the pump. Anti-foam

agents cause the air to break-out rapidly by lowering the surface tension of the air

bubbles.

Silicone based compounds are suspensions of ultra-fine silica particles in a silicone fluid

carrier. They are very effective, even when added after foaming occurs. Polyglycol

ethers, such as polypropylene glycol, are effective defoamers only when present before

the entrainment. However they are less expensive and therefore are more extensively

used. Treatment doses are in the range of 0·05 - 0·1% BWOW. They are most commonly

added to the mix water before mixing.

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1.2.4.81.2.4.8 ADDITIVES IN PRACTICE ADDITIVES IN PRACTICE

SECONDARY EFFECTS

Some additives have secondary effects on other cement properties. For example using

CMHEC as a fluid loss additive retards hydration and increases slurry viscosity.

Figure 6.2.8: Affect of Various Additive Types on Hydration Time.

INFLUENCE OF PHYSICAL CONDITIONS ON ADDITIVE PERFORMANCE

As with all additives, the physical conditions of storage, mixing and placement can have

a significant impact of their performance.

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Figure 6.2.09: Effect of Physical Condition on Retarder Performance.

ADDITIVE QUALITY CONTROL

Additive effectiveness can be control by many factors.

Cement property variance.

Physical conditions.

Mix water chemistry and contaminants

Preparation and placement conditions.

Additive quality

Age versus shelf life and storage conditions.

Additive interaction (+ve synergy or the opposite)

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Some additives and combinations under certain conditions can give rise to a 'Reverse

Temperature Effect'. Hydration modifier performance is inversely proportional to the

temperature profile over a specific temperature range.

Quality testing is essential to obtain a slurry composition with requisite properties. All

samples must be taken from all ingredients to be used for the cementing job on hand,

including the mix water.

ADDITIVE MIXING

Dry Blending with Cement

The mixing of a relatively small quantity of a powdery product, typically 1% into a large

matrix is rather problematic and can easily result in a poor, inhomogeneous distribution.

This method is not recommended.

Mixing in the Mix-Water

This affords a good control over the actual rates applied and ensures a consistent

treatment. Although waste is incurred because, as a contingency, most of the time the

volume of mix water prepared is larger than actually needed for the job, the simplicity of

the operation and the accurate dosing makes this the preferred route.

It is essential to ensure that the crew only mix at the desired concentration. "Finishing the

bag" with some additives (such as high performance retarders) can significantly affect

slurry performance.

Mixing liquid additives 'on the fly'

Liquid additives are fed directly into the mix water tanks of the cement unit when filling

up. This avoids the waste of the mix water quantity. Accurate dosing requires a reliable,

often complicated, metering system able to stand the rigours of a cementing operation.

This method therefore can be recommended only for advanced and integrated operations.

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1.2.4.91.2.4.9 SPECIAL PURPOSE CEMENTS SPECIAL PURPOSE CEMENTS

THIXOTROPIC CEMENT

In lost circulation situations a thixotropic slurry may resist losses to the formation by

rapidly developing a self-supporting gel structure. This carries part of the hydrostatic

pressure of the cement column thereby reducing the bottom hole pressure. Shear breaks

the (fragile) gel structure making it possible to pump the slurry.

Thixotropic slurries are often used for plug cementations to avoid slumping into the

lighter fluid.

The thixotropy is generally achieved by adding gypsum. Bentonite will also increase the

thixotropy of a slurry.

FOAM CEMENT

Foam cement is created by injection of air or nitrogen and a surfactant into a

conventional neat slurry. It will create a light weight slurry with a gradient limit of about

8 kPa/m (6·8 ppg). It will develop a lower compressive strength than neat cement.

Caution needs to be taken with well control as the slurry will have a variable hydrostatic

head due to compression of the gas bubbles.

ULTRA FINE CEMENT

Portland cement clinker is ground to a much smaller, nearly sub-micron particle size. The

smaller size allows the particles to pass through pore throats. The cement forms an

internal filter cake resulting in better sealing and shut-off after setting.

SURFACTANT CEMENT

Surfactants are added to the slurry formulation to aid in gas influx control. However their

effect remains unproven and most migration is believed to be via micro-annuli which

remain unaffected.

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Cationic surfactants precipitate the positively charged cement particles and accelerate

setting.

LATEX CEMENT

Cements with >25% BWOC latex added have a higher tensile strength than ordinary

cement that resisting stress cracking from subsequent temperature and pressure

fluctuations.

FIBRE CEMENT

In this development from Shell, polypropylene fibres are added to a conventional slurry.

The fibres increase the tensile strength of the set cement which will improve the cement

sheath integrity during subsequent drilling phases. The fibres also resist fluid losses in

fractured formations.

SLAG-MIX CEMENT

A blast furnace slag, together with an activator (lime or caustic soda), is mixed with a

drilling fluid in conventional cementing equipment. The main advantages are less

shrinkage, <1%, and waste reduction by using the drilling fluid.

Extensive testing of the mix is required to achieve the desired results. Do not use the

drilling fluid after sampling for testing as its composition may change thus affecting the

setting characteristics.

1.2.51.2.5 Gas well cementing Gas well cementing

Many wells with gas bearing formations have pressured annuli and potentially dangerous

situations. Subsequent repair operations are often difficult and expensive. Several

possible mechanisms for gas migration have been postulated. The major ones, dealt with

in this topic, are:.

Incomplete drilling fluid dispacement

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Low bottom hole pressure during displacement

Gas channelling

Subsequent micro-annulus development

The solutions that have been postulated and/or used for dealing with the problem are also

given.

1.2.5.11.2.5.1 MECHANISMS OF MIGRATION MECHANISMS OF MIGRATION

INCOMPLETE DRILLING FLUID DISPLACEMENT

The primary cause of gas migration is attributed to incomplete mud displacement. If the

resulting fluid column of mud and spacer above the zone exerts too low a hydrostatic

pressure to contain the gas then gas influx and migration can occur. Resolving this

problem is dealt with more fully in the section dedicated to cement placement.

LOW BOTTOM HOLE PRESSURE DURING DISPLACEMENT

Failure to maintain an overbalance during all phases of displacement can lead to a gas

influx into the moving slurry. Depending upon the severity of the under-balance, the

form, this can vary from gas cutting to major channelling.

Generally the designed cement slurry will provide sufficient overbalance when in place.

The problem usually arises when lightweight 'scavenger' slurries or spacers are used.

Contractor software packages predict the bottom hole pressures during displacement and

should be consulted to ensure adequate well control throughout. 'Cementing' in Wellplan

for Windows can also be used to check for well control.

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Figure 6.2.10: Potential gas migration path

  GAS CHANNELLING

The channelling of gas through, or past, a 'set' cement matrix has been identified as

recurring problem by many operators. Considerable effort has been made to find the

mechanism/s governing this channelling. However there is still no consensus on the

actual mechanism of gas influx and migration in cement. The following summarises the

SIEP RTS viewpoint.

Directly after cement placement the hydrostatic gradient of the cement slurry, and the

other annulus fluids, provides the bottom hole pressure. However during setting the

cement will develop gel strength, or a resistance to flow. Ultimately this gellation

becomes so strong that the cement becomes self supporting; i.e. it 'hangs' in the annulus.

Consequently hydrostatic pressure can not be (fully) transmit through the column.

In this situation the pressure exerted by the gel on the formation will equilibrate with the

pressure in the gas bearing zone. This phenomena is widely reported by researchers into

this subject. Refer to the first chart in Figure 6.2.11 which shows the measured bottom

hole pressure after cement placement. This equilibration in itself does not lead to a gas

influx. Only when a volume reduction in the gelled cement occurs, does gas have the

opportunity to flow into the wellbore.

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Fluid loss from the gelled cement to a permeable formation has been implicated as a

mechanism for this volume reduction. Hence a lot emphasis has been placed on

controlling fluid loss. However, fluid loss can only take place when there is a pressure

differential between the cement and the gas zone. As there is pressure equilibrium

between the gelled cement and the gas zone, fluid loss cannot occur. Chart 4 of Figure

6.2.11 indicates that fluid loss is restricted to a very short period after displacement, is a

minimal volume and does not correlate with bottom hole pressure loss.

Figure 6.2.11: General Experimental Data from RTS Gas Migration Studies

Other mechanisms of volume reduction of gelled cement are unknown, implying that gas

influx or gas migration is unlikely to occur in this stage. This is confirmed with chart 3 of

Figure 6.2.11 which shows that gas influx occurs after the cement has achieved a solid

state. Additionally the very high gel strength will resist migration of the gas through the

cement gel matrix.

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The cement then passes from the semi-fluid gel state into a two phase system, a solid

with a fluid-filled pore structure. Oil well cements all have a certain degree of shrinkage

in this process. Total volume loss is typically in the order of a few percent. This can lead

to a reduction in bottom hole pressure causing gas influx into the well bore. This is

shown in chart 3 of Figure 6.2.11 which clearly shows gas influx. This is not a problem

for a well developed cement pore structure without channels or voids. The permeability

of the set material is in the order of nanoDarcys and is low enough to resist any gas flow.

The overall physical shrinkage however can lead to a micro-annulus at the cement/pipe or

cement/formation interfaces. Most formations however are sufficiently plastic to move

inwards as hydrostatic pressure is relaxed and close off this micro-annulus. On the other

hand, shrinkage of the cement around the pipe may cause bond failure and the pipe

cannot follow the receding cement. This failed bonding can then provide a leak path for

the gas. This is shown in chart 3 of Figure 6.2.11 which clearly shows continued gas

flow. Physical observation confirmed that the gas migration path was through a micro-

annulus around the inner pipe.

Internal shrinkage may lead to stress fractures in the matrix. These must connect up to a

continuous channel is migration is to occur over the whole column. This is not believed

to be a common failure mechanism.

SUBSEQUENT MICRO-ANNULUS DEVELOPMENT

Pressure and temperature cycles inside the well (during subsequent drilling and

production operations) cause expansion and contraction of the cemented pipe. This can

lead to failure of the bond and result in leak paths around the cement. This is responsible

for the observation of (slow) annular pressure build-up during the weeks or even years

after the cementation has taken place.

Some researchers have identified that with high solids drilling fluids there can be

significant filter cake development on permeable formations. In linear cement

displacement there is generally insufficient erosion to remove this cake. If gas is allowed

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to percolate into the well bore it may dehydrate this cake and gradually form a channel.

This will only be over a short length but may result in interzonal communication.

1.2.5.21.2.5.2 SOLUTIONS SOLUTIONS

1.2.5.2.1 HISTORICAL SOLUTIONS

The problem of gas influx into the cement matrix has historically been attacked in many

ways.

Lower Top of Cement

If the cement column above the gas bearing zone is shorter the effect of shrinkage is

reduced and therefore the amount of gas influx will be reduced. A short cement column

may lead to well control problems, thus a two stage cement job may be required. This

solution is unproven.

Mud Hydrostatic or Annular Pressure

Increasing the mud gradient, or applying annular back pressure, will increase the initial

overbalance on the gas zone. Sufficient overbalance will avoid gas influx. When

considering this type of solution the formation strength must be carefully taken into

account. This solution is unproven.

Cement Fluid Loss

Fluid loss of the cement slurry during the hydration phase will increase the problem of

volume and therefore pressure reduction. Unproven in the experiments.

Shorter Transition Time

Gas influx into the cement matrix is restricted to the period during which the hydration

process takes place. As short as possible transition time between the slurry phase and

hardened cement is therefore essential to reduce the effect of gas influx. This is termed

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'right angle set'. Unproven in the experiments as gas influx occurs after set. Additionally

the cement gel strength is sufficiently high enough to resist gas migration.

Additives

Several additives are marketed to control the migration of invaded gas.

Surfactants are claimed to result in a foam which has a higher resistance to movement.

Sufficient shear energy to form the foam is unlikely in the case of migrating gas and is

limited to the gel stage.

Latex particles commingled into the cement will be forced to the pore throats and will

prevent further gas percolation. In sufficient concentration, latex can give the resultant

cement sufficient flexibility to yield under shrinkage and deform to maintain pipe and

borehole bond. Unproven, cement already has an extremely low permeability and it

requires very high latex concentrations (>25% BWOC).

Microsilica is claimed to also block the pores in the cement gel structure. Shell Oil are

advocating the use of salt saturated mix water. When the mix water starts hydrating with

the cement the salt becomes supersaturated and will therefore crystallise and block gel

pores

Several expanding cement formulations have been marketed. Aluminium powder when

added to the slurry and exposed to the higher bottom hole temperature will react with

water to form hydrogen gas. This causes expansion of the cement volume during the

setting phase. There is a risk of hydrogen percolating to surface and expansion is limited

to the gel stage.

1.2.5.2.2 ALTERNATE SOLUTIONS

All of the above historic solutions, excluding latex, do not address the issue of subsequent

pipe to cement movement and the development of micro-annuli.

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RTS investigations into the mechanism of gas influx and migration have led to the

conclusion that modifying the cement is not the complete solution. This issue of

subsequent micro-annuli development still remains. Therefore they recommend using a

mechanical sealing technique such as Gemoco rings. They are encouraging service

contractors to develop more modern and durable versions of these rubber type seals.

External Casing Packers (ECPs) are thought to also be a viable option. These are dealt

with in Section 5 Part 2 : "Casing and cementing operations".

Figure 6.2.12:

Comparison of Gas Migration Sealing Methods

1.2.61.2.6 Cement testing Cement testing

Prior to a cement job, laboratory tests must be carried out to ensure that the correct recipe

is used considering all of the existing conditions and additive properties.

1.2.6.11.2.6.1 BASIC REQUIREMENTS BASIC REQUIREMENTS

Apart from the cementing programme, providing the basic conditions and requirements

for the slurry design, samples of all ingredients from the wellsite should be sent to the

laboratory for the final testing. This includes the cement and the mix water. The

importance of representative sampling and use in testing cannot be over-emphasised.

Cement, although satisfying all API requirements, will still show variations between

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batches. The mix water may vary in its chemical composition (such as tannins or

chlorides) and this can affect setting times.

1.2.6.21.2.6.2 SLURRY DESIGN SLURRY DESIGN

The quality and supply of mix water are of prime importance in the design of the slurry

and selection of additives. Presence of contaminants in the water can have a significant,

often adverse, effect on slurry properties.

In general fresh water is the preferred quality for onshore operations. In offshore

operations where salt-intolerant additives need to be used fresh or drill water has to be

supplied from shore.

In offshore operations the mix water of choice obviously is sea water. It has the

advantage of (slightly) accelerating the setting of cement (reducing WOC time) and

improving compressive strength by as much as 20%. A defoamer will be required to

combat foaming.

For cementing operations through salt formations saturated brines are required to mix

slurries. Mimicking the composition of the formation salts is recommended to avoid

washouts and improve the final cementation. This imposes restrictions on many

additives, particularly fluid loss controllers, which are salt-intolerant.

1.2.6.31.2.6.3 GRADIENT GRADIENT

One of the main criteria is maintenance of pressure control and to avoid exceeding the

formation fracture propagation pressure.

To achieve the desired gradient all API class cements can be used for values between 17

and 20 kPa/m (0·75 to 0·88 psi/ft), varying the water to cement ratio between 0·61 and

0·34 m3/tonne (6·9 to 3·8 USgal/sack). It should be taken into account that adjusting

slurry gradient this way will have a significant effect on other properties as well, notably

rheology and compressive strength. For gradients above and below the range above

weighting material or fillers have to be added.

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Because of the high energy of the mixing devices there is a tendency for slurries to be

aerated. Therefore the slurry gradient should always be measured with a pressurised mud-

balance.

Figure 6.2.13: Pressurised Mud Balance

1.2.6.41.2.6.4 THICKENING/PUMPING TIME THICKENING/PUMPING TIME

The duration of the cement placement (job) is estimated by defining the amount of slurry

to be pumped and the expected pump rates to be used. Both pressure and temperature

accelerate the hydration process. Of the two , temperature is the most effective. Therefore

testing must then be carried out, under simulated conditions, to ensure that the cement

slurry will remain in a liquid state during the placement phase.

Hydration time is measured with a high pressure high temperature consistometer,

following API specification 10A: 'Testing of oil-well cement'. For deep well testing

special units are available accommodating temperatures up to 316°C (600°F) and

pressures as high as 276 MPa (40,000 psi). For well-site use, a portable, single cell

consistometer is available. Measured thickening times compare well with those obtained

in the laboratory using full-size equipment.

The slurry is placed into the test cell and the temperature and pressure are regulated to

simulate the conditions to be encountered during a cement job.

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Figure 6.2.14: High Pressure High Temperature Consistometer and Typical Hydration Time Test

The heating schedule is obtained from API Spec 10B. The viscosity of the slurry is

measured continuously and recorded as dimensionless Bearden consistency units. The

time during which the slurry viscosity stays below 30 Bc units is defined as the pumpable

time. The thickening time is when the slurry achieves at 70 Bc units of consistency.

Laboratory studies have shown that measuring the exothermic heat generated is a more

reliable method of determining the onset of slurry set. Equipment using thermal methods

is available but not routinely used at present.

1.2.6.51.2.6.5 COMPRESSIVE STRENGTH COMPRESSIVE STRENGTH

In most cases the compressive strength developed by oil-well cements is more than

adequate to satisfy requirements. A minimum compressive strength of 3,450 kPa (500

psi) is generally considered adequate for most operations.

The testing is performed by the unconfined crushing of prepared cubes which have been

cured for a set time, usually 24 hours.

Halliburton's Ultra-sonic Cement Analyser (UCA) has enhanced the compressive strength

measurement capability. The UCA makes a continuous record of the bulk

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compressibility, under controlled conditions, by measuring ultra-sonic velocity changes.

The measurement is also used to calibrate cement evaluation log responses.

Figure 6.2.15:Ultra-sonic Cement Analyser

1.2.6.61.2.6.6 RHEOLOGY RHEOLOGY

Analysis of the rheology of a cement slurry is important for its evaluating pumping and

placement parameters. The Power Law relationship is used as it most closely models the

flow behaviour. The rheological characteristics are largely determined by the water

cement ratio and the surface area of the cement particles. An ordinary API oil-well

cement slurry, with a water/cement ratio of 0·44 m3/tonne will have a higher viscosity

than a Pozzolan cement with a ratio of 0·95 m3/tonne.

The flow properties of a cement slurry are measured with the Fann Model VG-35, as used

for drilling fluids. The rheological properties are entered into the software packages to

model displacement efficiency and equivalent circulation density (ECD) for pressure

control.

1.2.6.71.2.6.7 FREE WATER FREE WATER

Free water is defined in the clear liquid that appears on the cement slurry when left to

stand. As such it is a measure for the stability of the formulation. Clearly a slurry with a

high volume of free water is undesirable as this water will collect on the high side in a

deviated or horizontal hole, greatly reducing zonal isolation and sealing properties of the

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set cement. Therefore attention should be paid to this phenomena in the slurry design,

particularly in horizontal well cementing.

Free water is measured by filling a glass cylinder with slurry and allowing it to stand for

a set period.

1.2.6.81.2.6.8 FLUID LOSS FLUID LOSS

Excessive loss of water from a slurry will adversely affect the hydration and final

strength of a cement. The fluid loss of a cement slurry is measured in an API HPHT Fluid

Loss Unit after conditioning the sample at bottom-hole circulating temperature and a

pressure of 6·9 MPa (1,000 psi). The fluid loss cell is fitted at the bottom end with a 325

mesh screen (44 micron openings), supported by a 60 mesh one. The filtrate is collected

for 30 minutes.

1.2.71.2.7 Cement placement Cement placement

Placement of the cement i.e. the complete removal of the mud from the annulus and its

replacement by a homogeneous cement slurry is a major requirement for a good cement

job . Cement placement is a function of a number of parameters such as drilling fluid

condition, the presence of a good spacer, pipe movement, displacement velocity, slurry

properties, pipe eccentricity and contact time. Good cement placement can only be

achieved when all parameters are optimally fulfilled.

1.2.7.11.2.7.1 SPACER FORMULATION SPACER FORMULATION

The main functions of a spacer are to separate the cement slurry from the mud, to assist in

mud displacement and to condition the walls of the bore hole for effective cement

bonding.

When using a water based drilling fluid water is the preferred spacer fluid. It has the

lowest viscosity to promote turbulent flow which gives the highest scouring action. When

the spacer must be weighted due for pressure control then some viscosity must be

provided to maintain the weighting material in suspension.

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A mixture of some cement powder and mix water with a specific gravity of some 1·50

kg/l provides an excellent cement spacer. Termed a 'scavenger slurry' it has a very low

viscosity with sufficient abrasive cement grains to ensure a good filter cake removal.

When an oil base drilling fluid is used it is essential to ensure that the borehole is water

wet. The spacer system is usually base oil followed by water containing water wetting

surfactants.

1.2.7.21.2.7.2 CONTACT TIME CONTACT TIME

The contact time is defined as the time during which a certain point of the formation is in

contact with a flowing cement slurry or spacer fluid. It is recommended to have at least 4

minutes of contact time.

1.2.7.31.2.7.3 DRILLING FLUID CONDITION DRILLING FLUID CONDITION

Complete displacement of the drilling fluid is essential for a good cement job. To achieve

this the fluid in the wellbore must easily mobile. In most cases a well formulated and

maintained drilling fluid will be easily displaced, assuming reasonable stand-off.

The gel strength of the drilling fluid is the most important parameter to monitor. In

general the gels should be moderate and flat (10 minute < 2 x 10 second). The drilling

fluid should be circulated prior to pumping the cement and the annular velocity should be

at least as high as that used during drilling. Circulation should be continued for a

minimum of one hole volume or until returns are free of cuttings and gas.

 

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