05.Politecnico Di Torino Drilling Fluids Programme 2011

05. DRILLING FLUIDS PROGRAMME

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C H A P T E R 5

DRILLING FLUID PROGRAMME


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5.1-2. DRILLING FLUIDS

(cost: up to 35% of the project)


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Drilling fluids are usually two-phase systems: the fluid phase and the solid phase.

• The fluid phase may be formed by only one fluid (water, oil or gas) or by two immiscible fluids (water and oil, water and gas), in which various chemicals (salts, alkaline or acid compounds, polymers, surfactants) can be dissolved to change or to control certain fundamental properties of the drilling fluid itself.

• The solid phase consists of particles of various nature and size maintained in suspension by the liquid phase. They can derive from different sources, that is they can be added to the mud on purpose to obtain certain specific properties (bentonite provides the thixotropic behaviour of the mud, barite is a weighting agent used to increase the mud density) or can enter the system from the formations during the drilling process (drilled cuttings). While the former are beneficial for the system, the latter can severely change properties and performances of a drilling mud and should, therefore, be kept under control or eliminated.

5.2.1. INTRODUCTION


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Depending on the type of base fluid used as continuous phase, drilling muds can be classified in three main categories, that is:

• Water-Based Muds (WBMs): they can be formulated with fresh water, sea water, various types of brines and even salt saturated water, to or within which many different components can be added for obtaining the planned characteristics and performances.

• Oil-Based Muds (OBMs, SBMs): they can have as continuous phase water-free oils, an oil (diesel, mineral or synthetic low toxicity oils) with emulsified water or brine (inverted emulsion systems) or water/brine in which an oil has been emulsified (direct emulsion systems). Also in this case many different chemicals are added to the system to impart to it the desired properties.

• Gas-Based Muds (GBMs): in this case the continuous phase is a gas (usually air, nitrogen or carbon dioxide) with additions of various quantities of water. If the water is present in low percentages, the system is defined as “mist”; if the concentration of water is higher and foaming agents have been added to the system, one speaks about “foam” or “stiff foam”. Finally, if the gas is added to the mud, the system is referred to as “aerated mud”.

5.2.1. INTRODUCTION


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Continuous oil phase

with emulsified water/brine

Water-free oil fluids

Continuous water/brine phase with emulsified

oil

Oil-free water or

brine fluids

Air or gas with water and/or oil to form foam

Air or gas

alone

Invert Emulsion

OilDirect Emulsion

WaterFoamGas

GAS WATER OIL

FLUID PHASE

Classification of Drilling

Fluids Based on Their Fluid

Phase

5.2.1. INTRODUCTION


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Drilling fluids possess peculiar features and performances, which must ensure many crucial tasks on behalf of any possible rotary drilling process.

Here are basically included: facing formation pressures and supporting well control aims (density); hole cleaning with removal of cuttings (and other....) from the bottom of the

well providing their transportation up to surface (density & viscosity); cuttings and solids suspension when mud circulation is temporarily

stopped (gel strength et al.); supplying hydraulic power to the bit protection and stabilization of bare borehole walls (mud cake, typically); cooling and lubrication of bit and drill string (lubricant); reduction of drill string and casing weight, fatigue and wear (density),

where weight reduction is only a consequence; corrosion control (pH); command / check remote transmission, and data and information acquisition (about rocks and formation fluids).

5.2.2. MISSION OF THE DRILLING FLUIDS


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FACING FORMATION PRESSURES - SUPPORTING SPECIAL AIMSIt has already been pointed out that a timely and reliable prediction and quantification of pressure profiles (in particular of pore and fracture pressures) in a well are essential for a correct well planning and for safe and cost-effective drilling operations. The development of pore gradients versus depth determines the density a mud should have and how it has to be changed as a well is deepened. The correct selection of the mud density is the most important parameter a drilling fluid engineer has to define. In fact, until the hydrostatic head assured by the mud column in the well results to be higher than the formation pressure, no fluids can enter the wellbore and no problems take place; but if for any reasons the pressure exerted by the mud in the hole becomes lower than the formation pressure, hole instabilities, kicks or even blowout can occur, which can endanger the safety of the rig, equipment and environment and even the lives of the personnel. Of course the mud density should not be excessive, otherwise low penetration rates, formation fracturing, circulation losses and, consequently, high drilling costs can be the direct consequence.Therefore, the mud density should be maintained, if possible, 100-150 g/cc above the expected pore pressure gradient and always below the predicted fracture gradient.

5.2.2. FUNCTIONS OF DRILLING FLUIDS


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CUTTINGS REMOVAL AND TRANSPORTATION UP TO THE SURFACE The cuttings generated by the bit must be removed from the bottom of the hole and transported to the surface as quickly and as more efficiently as possible to ensure good penetration rates and prevent hole problems, such as stuck pipes, swab and surge. The mud physical properties that play a role in an adequate hole cleaning are viscosity, density and the flow rate used to circulate the mud in the hydraulic circuit. The mud viscosity is the here one of the most important parameters; in fact, it is well known that cuttings settle very rapidly in fluids (i.e. water) which have low viscosity, while the carrying capacity of a mud increases with its viscosity. Also the density improves the carrying capacity of drilling fluids, because, as it increases, also does the buoyancy effect on drilled solids. An efficient hole cleaning standard is also related to the difference between the velocity with which they are lifted in the annulus (annular velocity) and the velocity with which they tend to settle on the bottom of the hole because of gravity (slip velocity); the former is a function of the flow rate and increases as the flow rate increases, while the latter depends on solid particle size, shape and density.



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CUTTINGS AND SOLIDS SUSPENSION IN ABSENCE OF CIRCULATION

Another important function of drilling fluids is to maintain the solids, on purpose added to the mud, and the cuttings, produced by the bit, in suspension, when circulation is temporarily stopped; if cuttings and solids accumulate on the bottom of the well around the bottom hole assembly, they can cause problems such as pipe sticking and circulation losses.

This function is achieved because drilling fluids, composed for a certain amount by clay minerals and polymers, possess what is called a thixotropic behaviour, that is they are in a sol-like state when in motion and in a gel-like state when in static conditions.

The passage form one state to the other can occur indefinitely and this specific attitude is quantified and measured by the property of the mud called gel strength.



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PROTECTION AND STABILIZATION OF BOREHOLE WALLS

The filtration process, that is the partial loss of the water phase of a drilling fluid into a permeable formation, deposits on the walls of the wellbore what is called mud cake or filter cake, formed by the solids which are present in the fluid. The main effects of the filter cake are the protection of the rocks from further filtration (this is particularly important in the case of mineralized formations) and their stabilization, avoiding problems such as hole caving and sloughing. Obviously, an optimum quality filter cake – in order to be efficient – should be very thin, impermeable and elastic and should be able to self regenerate very quickly, otherwise problems such as hole tightening with a consequent increase in friction losses, pipe sticking and circulation losses could occur. A high initial filtrate (indicated as spurt loss) improves penetration rates in that it is able to diminish the differential pressure affecting the drilled cuttings (chip hold-down pressure) facilitating their removal from the bottom of the well. The mud filtrate amount should be kept within optimal values in order to minimize formation damage and the interaction of the water phase of the mud with reactive, sensitive formations, especially shales.



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COOLING AND LUBRICATION OF BIT AND DRILL STRING

The rotation of the drill string considerably heats the bit and the drill string itself because of their friction against the wellbore walls. This heat is partially adsorbed by the formations which are drilled and partially by the circulating mud, which is pumped into the wellbore at a quite low temperature.

Furthermore, some materials used in the mud composition (i.e. bentonite, water, surfactants) have a lubricating action lowering the coefficient of friction between the bit (and the drill string) and the drilled formations.

N O T I C E :Usually any drilling fluid is called INHIBITIVE when it has a significant content in chemicals able to interact with clays and shales, in order to prevent or to strongly limit their negative effects (swelling, ……..) while drilling.

5.2.2. FUNCTIONS OF THE DRILLING FLUIDS


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COOLING AND LUBRICATION OF BIT AND DRILL STRING The rotation of the drill string considerably heats the bit and the drill string itself because of their friction against the wellbore walls. This heat is partially adsorbed by the drilled formations and partially by the circulating mud, which is pumped into the wellbore at a quite low temperature (but not always).Furthermore, some materials used in the mud composition (i.e. bentonite, water, surfactants) have a lubricating action lowering the coefficient of friction between the bit and the drill string and the formations.

DRILL STRING FATIGUE AND WEAR REDUCTION The buoyancy effect of the mud, which increases with its density, lowers the weight of the tubulars run in the wellbore (drill string and casings) with respect to their weight in air, thus reducing the stress on the rig surface equipment (rotary table, crown and travelling blocks, mast and substructure). This effect becomes more and more important as the depth of a well and the weight of the tubulars to be run increase.



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CORROSION CONTROL

A drilling fluid should not be corrosive with respect to the surface and downhole equipment and should neutralize the effects of possible corrosive fluids entering the wellbore (i.e. O2, CO2, H2S).

This function is ensured by the pH of the mud, which is usually maintained at values of 9 and more, and through the addition of specific chemicals, such as oxygen scavengers and hydrogen sulphide scavengers.



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DATA GATHERING ON ROCKS AND FORMATION FLUIDSThe geological, physical and chemical analysis of the cuttings, lifted up to the surface by the circulating mud, allows the acquisition of data which are essential for safe and cost-efficient operations. In particular, it is possible to reconstruct the lithological and stratigraphic sequence of the formations crossed by the well (Master Log), which permits the comparison of the actual situation of the well with respect to the planned objectives; furthermore, many important decisions regarding, for example, casing setting depths, bit selection, deepening of the well or well abandoning can be taken.The presence in the mud of traces of oil, salt water and gas helps in understanding the type of mineralization of the various formations drilled. The chemical analysis of the mud and its filtrate (presence of specific ions: chlorides, sulphates, divalent cations, etc.) indicates if particular formation fluids have entered the wellbore or if special formations have been drilled (salt, gypsum, anhydrite, etc.).Recent developments in cuttings characterization achieved by Eni E&P Rock Mechanics Laboratories (i.e. indentation tests with determination of the mechanical properties of the cuttings, interaction between cuttings and drilling fluids, cuttings density and transit time measurements) allow the prediction of pore pressure gradients and support the solution of hole stability problems.All drilling rigs are equipped with dedicated units, called “Mud Logging Units”, which allow the complete real-time characterization of both drilled cuttings and muds.



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As said, drilling fluids are composed by a continuous phase (water, oil, gas or their combination), to which many different types of chemicals are added depending on the final performances a system is called to provide. These chemicals can be grouped in two categories:

“solutes”, which are soluble in water or oil and completely dissolve into the continuous phase becoming an integral part of its composition;

“solid materials”, which are not soluble and are maintained in suspension by the liquid phase. They can be furthermore subdivided into commercial solids, when added to the mud on purpose, and drilled solids, which are incorporated into the mud while drilling a specific formation. Solids can be classified according to their size (from colloidal to gravel dimensions), surface electrical charges (reactive as clays or inert as barite) and their specific gravity (high gravity solids as weighting materials or low/intermediate gravity solids as shales, sands for other purpose, etc)

Next Tables summarize the main components of the drilling fluids, grouped in the different main categories described above, that is: the continuous fluid phase, the solutes and the materials contributing to set up the solid phase.

5.2.3. MAIN DRILLING FLUID COMPONENTS


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SOLUTE TYPE MAIN FUNCTIONS

Salts/Ionic Compounds (NaOH, KOH, NaCl, KCl, CaCl2, CaBr2, KOH, Na2SO3,

ZnCO3, Na2CO3, NaHCO3, etc.)

Adjust alkalinity

Increase density (completion brines)

Aid inhibition of reactive formations

Prevent solution of evaporitic formations

Adjust water activity in inverted emulsion systems

Aid corrosion control

Combat cement contamination

Aid polymers solubilization

Polymers (anionic, non-ionic, cationic) Control viscosity

Control fluid loss

Aid inhibition of reactive formations

Aid deflocculation and flocculation

Avoid cutting dispersion

Surfactants Aid corrosion control

Improve lubrication

Minimize bit balling

Improve emulsion stabilization

Asphaltic derivatives Improve lubrication

Control fluid loss

Improve suspension properties

Main Drilling Fluid Solutes



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Some Solid Phase

Additives and Their

Functions

CATEGORY FUNCTION TYPE

Weighting materials Increase mud density Barite, Hematite, Calcium Carbonate

Clays Increase viscosity Bentonite. Sepiolite

Reduce filtrate

Increase lubricity

Aid in bridging

Hole stabilizers Plug microfractures Asphalts, Gilsonite

Reduce filtrate

Lost circulation materialsLCMs

Seal porosity Fibres, Flakes, Resins, Salts

Plug microfractures

Plug fractures

Solid state torque reducers Reduce torque and drag Graphite, Teflon Beads, Bentonite

Aid lubricity

Microspheres Reduce mud density (***) Glass Beads



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5.2.4. PHYSICAL AND CHEMICAL PROPERTIES OF DRILLING FLUIDS

The properties possessed by all drilling fluids systems can be divided into two main classes: physical properties; chemical properties;and can be measured on the mud itself or on its filtrate.

The first ones are depending in particular from both the liquid and the solid phases, while the latter are influenced by the solutes, including ionic species, polymers and other water- or oil-soluble compounds. Each fluid is designed in such a way to have and maintain a certain number of properties, those considered well suited for a specific field application or problem.

The laboratory and field tests required for the physical and chemical characterization of drilling fluids are based on the procedures set by the American Petroleum Institute (API) and by the International Organization for Standardization (ISO) and published in the Bulletins: ISO 10414 “Petroleum and natural gas industries – Field Testing of Drilling Fluids”, which consists of the following parts:- Part 1: “Water-based fluids”, ISO 10414-1: 2008, Second Edition, 2008-03-15, ISO 10414-1:2008 (E).- Part 2: “Oil-based fluids”, ISO 10414-2: 2002, First Edition, 2002-07-15, ISO 414-2: 2002(E). ISO 10416 “Petroleum and natural gas industries -Drilling fluids - Laboratory testing”, Second Edition, 2008-06-01, ISO 10416: 2008(E). ISO 13500: 2008 “Petroleum and natural gas industries – Drilling Fluid Materials – Specifications and tests”, which has been approved by CEN as EN ISO 13500:2008 without any modification, Third Edition, 2008-11-01. It supersedes ISO 13500:2006.


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The most important physical properties a drilling fluid must possess are: density: the selection of the density of the mud is function of the pore pressure and fracture gradients of the formations to be drilled; viscosity: it represents the internal resistance offered by the fluid to flow, that is to be circulated and maintained in motion. From it some important performances of drilling fluids depend such as their solids carrying and hole cleaning capacities and wellbore walls stabilization; yield point or yield value: this quantity represents the initial resistance offered by a fluid to be put in motion, that is the stress required to make a fluid to pass from static to dynamic conditions; gel strength: it defines the attitude of a fluid to form a gel-like structure and is mainly due to the electrostatic interactions of electrically charged products and chemicals such as bentonite, native clays, shales and polymers. The gel strength indicates the ability of a fluid to maintain the solids in suspension once circulation is stopped and the drilling fluid is in static conditions; filtrate: the liquid lost by a drilling fluid into permeable formations can cause formation damage and hole instability, though a certain amount (the “spurt loss”) can enhance penetration rate; sand content: this gives an indication of the amount of sand incorporated into the system while drilling. The sand concentration should be maintained as low as possible to limit its wearing effect on tubulars (drill string and casings) and surface equipment; oil-water-solid content: the knowledge of this parameter allows to define the gross composition of a drilling fluid and if the various components are correctly balanced for a given mud formulation; electric stability of water-in-oil emulsions: it quantifies if an emulsion of water (dispersed phase) in oil (continuous phase) is stable and up to which extent cake thickness: the cake can stop filtration and stabilize wellbore walls.



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The chemical properties, measured on both the whole mud and on its filtrate, comprehend: pH: it measures the concentration of hydrogen ions in a mud filtrate. Normally pH values around 9 and above, are maintained in most drilling fluid compositions because of the convenience to have all clay and shale particles negatively charged. Furthermore, most of the polymers used solubilise more easily in alkaline environments; alkalinity: this parameter indicates the concentration of other ions than H+ in a mud and in its filtrate, precisely that of carbonate and bicarbonate ions, which can provide important information about the rheological stability of water-based muds; chlorides concentration: it can indicate if salt waters are entering the wellbore or if salt levels are drilled. In mud system, where salts have been added on purpose, chloride ion measurements show the amount of salinity present in the mud; total hardness of water: this parameter measures the content in divalent cations (calcium and magnesium) of waters used in mud fabrication. Hard waters can negatively influence bentonite yielding and polymers action; MBT test: the methylene blue dye test is used to determine the cation exchange capacity of the solids present in a drilling mud. In bentonite-based drilling fluids, the MBT test gives an indication about the amount of reactive clays present, while for bentonite-free systems reflects the reactivity of the drilled solids; hydrogen sulphide concentration: in many areas of the world hydrogen sulphide can be encountered by itself or in association with hydrocarbons. Its prompt recognition is very important because it is very dangerous and even lethal to human life and highly corrosive with respect to downhole and surface equipment; general chemical analysis: many other ionic species can be measured (K+, lime, sulphates)



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The density of a drilling fluid is directly linked to other important properties such as solids content, Marsh viscosity, plastic viscosity, yield strength, gels and filtrate, as shown in these slides.



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Many different types of drilling fluids can be prepared by using the categories of products seen before. In accordance with their application, each Oil Company follows a specific criterion to classify them. The Table below lists the classification followed by Eni E&P.

NON-INHIBITIVE WATER BASED MUDS

INHIBITIVE WATER BASED MUDS

OIL BASED MUDS INHIBITIVE OR SPECIAL MUDS AT LOW

ENVIRONMENTAL IMPACT• Bentonitic Mud• Guar Gum Suspension• Bentonitic Mud with CMC• Low Solid Mud with Bentonite Extender• Lignosulphonate Mud• Chromelignin Mud • PAC Mud• PHPA Mud

• Salt Saturated Mud• AGIPAK Mud• KCl Mud• Gypsum Mud• Lime Mud

Diesel Oil I.E. Mud !00% Diesel Oil Mud Diesel Oil Mud with Relaxed Filtrate

• K2CO3 Mud• Potassium Acetate Mud• Water Based Mud for HT (>200oC)• Cationic Mud• Glycol-Based Mud • I.E Mud with Low Toxicity Oil• 50/50 I.E. Mud• I.E. Ester-Based Mud• I.E. Polyalphaolefins Mud

5.2.5. DRILLING FLUID possible CLASSIFICATION


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5.2.5.1. WATER BASE(D) DRILLING FLUIDS


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5.2.5.1.1. MAIN COMPONENTS OF

WATER BASE(D) DRILLING FLUIDS


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The water used to prepare a drilling fluid can be either fresh water coming from aqueducts or taken from lakes, rivers, streams, etc., or, as done more frequently, produced from water wells drilled very close to the well prior to start drilling. Sometimes, the make up water can be supplied in tanks.

When drilling offshore, sea water can be used at least for the preparation of the drilling fluids to be used in the shallower and larger holes, where no particular sophisticated systems are required. In some circumstances, also brackish water can be employed.

However, in all cases the composition of the make-up water must be analyzed to determine its hardness (concentration of calcium and magnesium ions) and the eventual presence and concentration of other ions, such as chlorides, sulphates, nitrates, presence of organic matter, bacteria, etc., that is all the substances that can affect the performances of the chemicals which are planned to be used to impart to the mud the desired characteristics.

If needed, the water has to be adequately treated to eliminate the undesired chemical and biologic species or fabricated from sea water (“drill-water”).

5.2.5.1.1.1. MAKE-UP WATER


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Drilling fluids are densified or weighted up to to control sub-surface pressures and stabilize incompetent formations. The Table below lists the most common solid phase weighting materials used in drilling muds.

MINERAL MAIN COMPONENT

SPECIFIC GRAVITY

MOHSHARDNESS

CALCIUM CARBONATE

IRON CARBONATE

BARIUM SULPHATE

HEMATITE

CaCO3

FeCO3

BaSO4

Fe2O3

2,65-2,71

3,7-3,9

4,2-4,5

4,9-5,3

3

3,5-4,0

2,5-3,5

5,5-6,5

5.2.5.1.1.2. WEIGHTING AGENTS


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The weighting materials to be effective have to possess the following main characteristics:

a high specific gravity so that the concentration of solids in the drilling fluid is not increased too much; low abrasiveness in order not to wear tubulars and surface equipment; ready availability; low cost.

Barite is by far the most common weighting material. It is easily dispersed and virtually insoluble in water. It is almost completely inert in water-based systems and is relatively non-abrasive. Some low grades of Barite may contain variable quantities of impurities, such as heavy metals ((Pb, As, Cu, Hg, etc.), which can pose problems in the disposal of drilling fluid wastes or alkaline-terrigenous compounds (i.e. CaSO4) which may behave as potential contaminants of WBMs.

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5.2.5.1.1.2. WEIGHTING AGENTS


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Viscosifiers are added to drilling fluids to increase their viscosity and improve their cleaning and suspension functions. Primary viscosifiers for water-based fluids are normally clays or polymers, which impart both pseudoplastic and thixotropic properties to the fluid.

The selection of the most appropriate product is dependent upon economics, logistics and the expected operative environment (temperature, water salinity, presence of bacteria, etc.). Other chemicals including salts and bridging polymers may enhance the properties imparted by the primary viscosifiers.

Bentonite is often used as the primary viscosifier in most WBMs due to its efficacy, low cost, availability. As the well conditions become more demanding, bentonite can be added or replaced with high molecular weight polymers, such as: high viscosity Carboxymethylcellulose (HV CMC), polyanionic cellulosic polymers (PAC), Xanthan Gum, Guar Gum, etc.

In systems using seawater, brines, gypsum or a commercial salt kind, bentonite must be prehydrated in fresh water before the addition of other chemicals; the slurry is referred to as Prehydrated Bentonite or PHB.

5.2.5.1.1.3. VISCOSIFIERS


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Polymers are widely used in drilling fluids manufacturing, owing to the many different properties they can impart. For this reason, a brief description of the main characteristics are here below proposed.

STRUCTURE AND BEHAVIOUR OF POLYMERS

The factors that determine the behaviour of a particular polymer are quite complex and often only small changes in the structure of the molecule can substantially alter its properties. This gives the polymers an inherent versatility, which is reflected in the wide variety of applications for which polymers are well suited as previously shown.

The most important variables from which the behaviour of polymers depends are:

molecular weight; type of functional groups present onto the molecule; three dimensional structure.



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Molecular WeightThe molecular weight, which is equivalent to say the chain length, of polymers can be varied by limiting the number of chain terminating groups or by chemical degradation of longer chains. Another important feature is the distribution of molecular weights; in fact, if this distribution is quite broad, the low molecular weight material, if in larger quantity, can dominate or at least modify the behaviour and performances of the higher molecular weight materials.

Polymers usually have molecular weights ranging between 1,000 up to 1,000,000 D and more.



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Type of Functional Groups The chemical reactivity of polymers strictly depends on number, type and distribution of the reactive functional groups which are attached to the molecule backbone. The groups that are present on polymers usually belong to one of these three categories: non-ionic; anionic or negatively charged; cationic or positively charged.

Non-ionic: the most common non-ionic groups typical of drilling fluid polymers are alcohols, ethers, esters, amides, alkyl halides, alkenes, etc. An important feature of these chemicals is that they all readily form hydrogen bonds with water and, therefore, can hydrate and ultimately solvate. Because non-ionic polymers (i.e. starch, guar gum, hydroxyethylcellulose) have no dissociable radicals, they result to be very stable in highly saline environments.



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Type of Functional GroupsAnionic: the anionic polymers owe their behaviour to the presence on their backbones of negatively charged groups such as: carboxylic, phosphate, phosphonate, sulphonate, sulphate, etc. While speaking about clays and shales, it has been pointed out that these rocks present on their surfaces negative charges and that the broken edges are also negative if the pH is kept on alkaline values. In order to further favour repulsive forces with respect to attractive forces, because this gives drilling fluids with the desired degree of viscosity and deflocculation, most polymers are consequently anionic (i.e. carboxymethyl cellulose, polyanionic cellulose, partially hydrolized polyacrylamide, lignosulphonates, polyacrylates, etc.).

Cationic: cationic polymers contain positively charged functional groups (i.e. ammonium) and are not normally used in drilling fluids manufacturing, because they will increase attractive forces, thus causing the flocculation of clays. They can serve as emulsifiers, wetting agents and surfactants.



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Tridimensional StructureThe shape or tridimensional structure the polymers can assume are very different and depends on several factors as the following: the type of monomers and comonomers from which the polymer derives which can produce long chains or differently branched and crosslinked structures; the concentration, type and distribution of the reactive groups on the molecules; the pH of the solution in which the polymers are placed as it changes their ionic character with effects on repulsive and attractive forces within and among the molecules; the salt concentration also affects the electrostatic repulsion between the charges and consequently polymer configurations. For instance, in case of an anionic polymer, if this is placed in fresh water, the negative charges present on the polymer molecules repulse each other and the polymer will assume a stretched elongated configuration; if, on the contrary, the polymer is in presence of monovalent and divalent cations (Na+, K+, Ca+2), these will neutralize the negative charges on the same molecule or on adjacent molecules, bridging them and thus producing a tightly coiled structure. The change in molecular shape will also change the physical properties of polymers in solution.



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STRUCTURE AND BEHAVIOUR OF POLYMERSTridimensional Structure



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POLYMERS USED IN DRILLING FLUIDS Though several hundreds of polymers are currently available on the market, from a strict chemical point of view they can be grouped in three main categories, that is:

natural polymers; semi-synthetic or modified natural polymers; synthetic polymers.



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NATURAL POLYMERS

These polymers directly derive from substances of vegetal or animal origin and, sometimes, from the action of microorganisms on these substances.

The most common natural polymers used in drilling fluids preparation are: Starch, which is a carbohydrate of vegetal origin, consisting of a large number of glucose units linked together by glycosidic bonds. It makes up the nutritive reserves of many plants (cereals: corn, wheat, rice, barley and tubers: potato, tapioca, cassava); Guar Gum, which is extracted from the beans of a leguminose plant called guar. It is non-ionic and shows a rapid hydration even in cold water. Xanthan Gum, which is a slightly anionic, water-soluble biopolymer produced by a process involving the fermentation of glucose or sucrose by a bacterium named Xanthomonas campestris, hence also its appellative XC polymer. Scleroglucan, which is a non-ionic, water soluble polysaccharide, containing many glucose units, produced with different techniques by submerged cultivation of the Sclerotium rofsii (it’s a filamentous fungus) in a glucose and water solution. Lignite products are natural, anionic, long-chain molecules with a structure similar to that of lignosulphonates.



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SEMI-SYNTHETIC POLYMERS

Also what are called semi-synthetic polymers are of natural origin and belong to the vast family of the carbohydrates. They are derived by synthesis introducing onto a natural substrate some specific functional groups with the purpose to improve certain physical and chemical properties of the original product (i.e. solubility in water, resistance to divalent cations, thermal stability, etc.). The most important ones are: Modified starches, which have been synthesized with the intent to improve the resistance to thermal degradation of the natural substances. The main modifications regard the introduction in the molecule of carboxymethyl or hydroxypropyl groups. Carboxymethyl Cellulose (CMC), which is a cellulose derivative with carboxymethyl groups (–CH2COOH). It is an anionic, water-soluble and chemically reactive polymer, available in different purity grades (technical, semi-purified and purified) and MW (high viscosity and low viscosity CMC). Polyanionic Cellulose Polymers, or simply PACs, which are CMCs with higher degree of substitution (DS>1) and molecular weights and in which the carboxymethyl groups are distributed along with the polymer molecules in a more orderly way than in standard CMCs. Lignosulphonates, which are derived from Lignin, the chief constituent of wood. They have complex structures that include aromatic rings and acid groups, such the sulphonated groups, that make them tolerant to most ionic species contamination.



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SYNTHETIC POLYMERS

Synthetic polymers are called so, because they are the result of reactions of synthesis and precisely of polymerization by addition.

The most common additives of this category, which find application in drilling fluids imparting to them a wide variety of properties, belong to the families of the polyacrylates, polyacrylamides and various copolymers (Vinyl Acetate – Maleic Anhydride or VAMA, Sulphonated Styrene – Maleic Anhydride or SSMA, Vinylsulphate – Vinylamide or VSVA) .


FUNCTION MOLECULAR WEIGHT NUMBER OF MONOMERS

Deflocculant 7,000 100

Fluid Loss Reducer 6,000 80

Flocculant 3,000,000 40,000

Bentonite Extender 10,000,000 130,000

Relationship between Molecular Weight and Function of Polyacrylates


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MATERIAL PRIMARY FUNCTION SECONDARY FUNCTION

BENTONITE

POLYACRYLATE

PAC

XANTHAN GUM

GUAR GUM

HEC

VISCOSIFIER

BENTONITE EXTENDER

VISCOSIFIER (USED IN GYPSUM-BASED MUDS)

VISCOSIFIER (FOR ALL SYSTEMS))

VISCOSIFIER (FOR HIGH VISCOSITY PILLS)

VISCOSIFIER FOR COMPLETION FLUIDS

FLUID LOSS REDUCER

FLUID LOSS REDUCER

FLUID LOSS REDUCER

FLUID LOSS REDUCER

DRILLED SOLIDS FLOCCULANT

LOW FORMATION DAMAGE



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The polymers used to reduce fluid loss in drilling fluids act according to three main mechanisms: they plug or block the pores of the formations drilled; they increase the viscosity of the water phase of the fluid; they, finally, deflocculate clays contributing to a more impermeable filter cake.

In the first case the polymer itself may cause the blockage of the pores if its dimensions are small enough and compatible with the size of the pore throats (about 1 μm or less). These polymers must not be completely soluble in water; therefore, starch and asphalt derivatives can function in this manner. Polymers can also adhere to suspended colloidal particles, determining an increase in their dimensions and thus contributing to the blockage of pore throats.

Another way to decrease fluid loss rates can be achieved by increasing the viscosity of the water phase; this effect can be performed by high MW polymers, such as guar gum, xanthan gum, HEC and HV cellulose polymers, particularly if they are also ionic, because they can create bridges among clay platelets promoting a better blockage through larger particle size.

Finally, anionic polymers favour the deflocculation and dissociation into smaller particles of suspended solids; this can result in a closer packing of the materials that form the filter cake, that will result, consequently, more impermeable. Lignosulphonates, low molecular weight cellulose derivatives and polyacrylates are the most effective at this regard, having a high anionicity and not too high molecular weights.

5.2.5.1.1.4. FILTRATION CONTROL AGENTS


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The additives, which can control fluid-loss, belong to two main categories:

particulate materials, that is materials characterized by very small dimensions so that they can enter the filter cake and lodge among the cake-forming particles decreasing its permeability. Additives with this behaviour are: bentonite, carbonate powder, lignite, asphaltic products, etc.;

water soluble polymers, which control fluid-loss through a combination of the mechanisms described above, though the main action is always due to the physical plugging of the pores of the filter cake. Water-soluble polymers can form weakly bonded colloidal aggregates in solution, which are sufficiently stable to become wedged on the filter cake constrictions. They can also be adsorbed on the surfaces of the grains, thus decreasing the size of the pores to occlude. The effect on water mobility, due to an increase in its viscosity, is by far less important than the mechanical plugging action. A wide variety of polymers exhibits these properties such as: low viscosity carboxymethylcellulose (CMC LV), starches, PAC, carboxymethylhydroxyethyl cellulose (CMHEC), sulphonated synthetic polymers.

The most common polymers used as filtrate reducers are starches and CMCs.



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Modified Starch

CMC

PAC

Synthetic Polymers

Sodium Humate

Lignite

Fluid Loss Reducer for High Salinity Systems

Low Cost Fluid Loss Reducer

Fluid loss reducer for moderately saline systems

Fluid Loss Reducers for High Temperature Applications (>200oC)

Fluid Loss Reducer for HT and Saline Environments

Low Cost Fluid Loss Reducer

Acid Soluble (with residue)

Viscosifier

Mild Deflocculant for Systems with Salts and not Weighted

Moderate Deflocculants

Deflocculant

Deflocculant



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With the term deflocculation it is meant a reduction in the number or degree of particle associations which are present in a colloidal suspension; as this process occurs, the viscosity of the suspension decreases. Some polymers, called deflocculants and improperly thinners or dispersants, help obtaining deflocculated systems. In most cases, they are anionic polymers with low molecular weight and, therefore, with short chains, which, because being negatively charged, are easily adsorbed on the positively charged sites of broken edges of shale platelets, causing them to behave as though they were completely anionic, too. Deflocculants, therefore, are used to control rheology when salts, temperature and excessive solids concentration cause increased viscosity.

Very often, small molecules, such as polyphosphates, or short chain polyacrylates can be used to deflocculate drilling fluids. But repulsive forces among shale or clay particles can be further increased by using larger anionic molecules (i.e. lignosulphonates); this introduces a sterical factor, which physically prevents the particles from approaching too much each other, resulting more effective at keeping a system deflocculated also in environments characterized by high salt concentrations and hardness.

5.2.5.1.1.5. DEFLOCCULANTS


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Deflocculants are generally used to extend the performance of water-based fluids, in particular in case of high temperature and high solid concentration (weighted muds). Deflocculants control the rheological and thixotropic properties by decreasing the degree and strength of the colloidal particle associations in drilling fluid suspensions.


Sodium Acid Pyro Phosphate, SAPP

Ferro-Chrome Lignosulphonates

Polyacrylates

Sodium Salts of Polycarboxylic Acids

Strong Deflocculant

Deflocculant for All WBMs

Deflocculant for All WBMs

Deflocculants for HT Conditions (up to 250oC)

Calcium Precipitation

Fluid Loss Control

Fluid Loss Control

Fluid Loss Control

5.2.5.1.1.5. DEFLOCCULANTS


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With the term “shale stabilization” it is usually meant the mechanism which retards the adsorption of water and the consequent swelling/dispersion processes to which most shales and clays undergo because of their electrical charges and their consequent reactions with water, salts and polymers. Most polymers currently available to the Oil Industry or used in the past are able to stabilize shales to more or less acceptable levels. The polymers used for this purpose go from cellulosic derivatives to xanthan gum, starch, lignosulphonates, PHPA and even non-ionic types such as HEC.

The choice of the most appropriate polymer depends, at least in theory, on the mechanism which is supposed to influence the above mentioned processes. Among them, it is worth recalling: polymer adsorption (or encapsulation) onto shale surfaces; the reduction of the erosive action of the drilling fluid circulating in the annulus by decreasing, for instance, friction against the wellbore walls; pore blocking with a reduction of formation permeability and consequently of cations exchange and hydration.

A correct mud density is also critical in minimizing wellbore instabilities, at least in the short time.

5.2.5.1.1.6. SHALE STABILIZATION ADDITIVES


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Depending on the particular characteristics of the clays and shales to drill, many chemicals and systems are available on the market. They act according to various mechanisms, such as:

balanced activity: inverted-emulsion muds; cation exchange: potassium, calcium, aluminium salts; encapsulation: polyacrylamides, lignosulphonates, PAC; plastering (plugging of microfractures): gilsonite, asphaltic products; increased fluid density: addition of weighting materials.

5.2.5.1.1.6. SHALE STABILIZATION ADDITIVES


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Lost circulation materials (LCMs) are used to stop excessive losses of drilling fluid into permeable or fractured formations. Lost circulation materials are classified as flaky, granular or fibrous. Mechanisms for stopping losses include: matting, bridging and plugging (sometimes using natural resources too………).

Many substances can be used for regaining circulation: Flaky materials include cellophane, mica and wood chips. They are best for plugging and bridging porosity and microfissures. Fibrous materials include pulverized sugar cane stalks, cotton fibres and wood fibres. They work by penetrating and forming a mat on fractures or pores on which other solids can build on. Granular products include diatomaceous earth, ground walnut hulls and calcium carbonate. They work by plugging pores and microfissures.

Many products contain a mixture or proprietary blend of these. Often, the choice of which product to use is based on trial and error experimentation or by previous experiences in an area. Lost circulation materials are often incorporated into various lost circulation plugs and slurries, including cement slurries, "gunk (DOB) plugs” , etc.

5.2.5.1.1.7. LOST CIRCULATION MATERIALS


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Many inorganic and organic additives can enter into a mud formulation to impart basic and specific properties or to counteract any eventual contamination. Among the most common chemicals used for this scope, it is worth mentioning:

pH and alkalinity control additives have influence on many drilling fluid properties. The solubility and effectiveness of most water-based drilling fluid components are improved at proper pH conditions, including clays, polymers and thinning chemicals. Alkalinity is important in terms of suppressing the solubility of contaminating ions and molecules such as Ca2+, Mg2+, H2S and CO2.

Surfactants are used to alter the surface chemistry of drilling fluid components, steel pipe or formation materials. They modify or reduce surface tension at the interface of various water-based fluid phases. Surfactants are used to combat bit balling and cuttings sticking to drilling tools. This results in better ROP's and easier wiper trips. Surfactants are usually organic compounds that are amphiphilic, meaning that they contain both hydrophobic groups (their "tails") and hydrophilic groups (their "heads"); therefore, they are soluble in both organic solvents and water.

5.2.5.1.1.8. CONDITIONING CHEMICALS

http://en.wikipedia.org/wiki/Organic_compound

http://en.wikipedia.org/wiki/Amphiphilic

http://en.wikipedia.org/wiki/Hydrophobic

http://en.wikipedia.org/wiki/Hydrophilic


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Lubricants are used to reduce rotary torque and hole drag in deep and, in particular, in directional and horizontal wells.

Corrosion inhibitors are a broad class of conditioning chemicals. They are expected to work in corrosive environments by various mechanisms or combinations of mechanisms. Corrosive gases include H2S, CO2 and O2, or any combination of all three. Several factors affect corrosion rates, including holes temperature and pressure.

Bactericide is the generic name given to any substance that kills bacteria. Bactericides vary greatly in their potency and specificity. They may include other organisms and many different chemical compounds. Bacterial growth may result in the destruction of drilling fluid polymers. resulting in a loss of filtration or suspension properties. Sulphate Reducing Bacteria (SRB) can generate H2S through the degradation of sulphur-containing chemicals in concentrations high enough to be lethal. Microorganisms may produce enzymes, which also attack and decompose organic materials. Thus the selection of the proper bactericide is extremely important.



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Defoamers are used to combat foam in drilling fluids; foam is undesirable because pumps and solids equipment efficiency rates are hampered by it. Foam also increases corrosion rates and leads to erroneous PVT estimates. When not treated properly severe foaming problems can lead to a complete inability to pump. Defoamers are also used to remove entrained air or gas from fresh water fluids. They work by reducing the surface tension of bubbles. Because so many variables can contribute to foaming problems, pilot testing is often conducted at the rig to aid in choosing the most efficient product. They can be higher alcohols, sulphated vegetable oils and aluminium stearate.

Freeing Pipe Spotting Fluids are used to aid in freeing differentially stuck drill pipe. They often contain a blend of several constituents. The main working mechanism involves drying or dehydrating the filter cake and decreasing friction coefficients.

Oil may be occasionally added (up to 4-6%) to water-based fluids to improve certain properties, such as lubrication.



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Inorganic chemicals perform a diverse number of functions in water-based fluids, including: densification, contaminant precipitation, corrosion control, pore plugging and alkalinity control. The Table below lists some of the most frequently used inorganic chemicals.

CHEMICAL FORMULA DESCRIPTION FUNCTIONAMMONIUM BISULPHITECALCIUM BROMIDECALCIUM CHLORIDE

CALCIUM HYDROXIDE

MAGNESIUM CHLORIDEPOTASSIUM CHLORIDEPOTASSIUM HYDROXIDESODIUM BICARBONATESODIUM CHLORIDESODIUM HYDROXIDESODIUM SULPHITEZINC CARBONATE

NH4HSO3

CaBr2

CaCl2

Ca(OH)2

MgCl2KCl

KOHNaHCO3

NaClNaOH

Na2SO3

ZnCO3

White crystalsWhite powderWhite powder/flakes

White powder

White crystalsWhite or pink crystalsWhite beads or flakes White powderWhite crystalsWhite beads or flakesWhite crystalsWhite powder

Oxygen scavengerHeavy clear brinesCalcium treated fluids, heavy clear brines, freeze point depression,Flocculated water systems, alkalinity controlLime treated system, pH controlPotassium treated fluidsAlkalinity control in K+ systemsTreatment of cement contaminationBrine formulation, bridging agentAlkalinity controlOxygen scavengerH2S scavenger



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5.2.5.1.2. TYPES OF WATER-BASE(D) DRILLING FLUIDS


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Spud muds are used to drill surface holes. Usually the main function of a spud mud is to clean the well from the cuttings. Surface hole JUMBO bits have bigger teeth than normal bits, generating bigger cuttings. Because surface holes are of such large diameter (up to 36"), annular velocities are low, even at maximum pump rates. This means that spud mud viscosities have to be usually high.

When choosing a spud mud, the two main considerations are the formation pressure gradient and the availability and type of make-up water. If surface formations are underpressured, lost circulation is a problem and fluid densities must be kept low. Occasionally abnormal pressures are encountered on top hole; in these cases, the spud mud must retain the ability to suspend Barite.

Spud mud systems and components must conform to certain criteria; for example, the products must be able to be mixed rapidly using simple recipes and the systems must be economical.

Make-up water analysis is always essential prior to mixing any fluid system, especially spud muds. Contaminants such as calcium or magnesium must be precipitated to ensure a proper performance of mud components.

5.5.1.2.1. SPUD MUDS


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On land, the top hole is usually drilled with one of the following spud mud systems:1. Native Solids2. Bentonite/Lime3. Bentonite4. Extended Bentonite

The funnel viscosity (Marsh viscosity) of these systems is usually maintained at 40-60 s/litre until casing depth is reached, where it might be raised to 80-120 s/litre to facilitate running casing. In some areas, it is advisable to start with and maintain a viscosity above 150 s/litre until the 11 and 9-inch drill collars are drilled down. The improved cleaning characteristics reduces time spent laying down big collars when difficulty is encountered making connections in incompetent formations such as gravel.

When lost circulation or gravel is encountered, the viscosity should be raised to 150 s/litre or higher.

Other important properties include pH, alkalinity and density. Spud muds are often discarded after use.



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Native solid systems are used in areas where "mud making" clays are encountered. The well is spudded with fresh water and viscosity builds naturally. Caustic, lime or bentonite may be added to these systems as required to increase the viscosity.

Bentonite/Lime slurries are often used on shallow surface holes. Usually about 60 kg/m3 of Bentonite are added to fresh water until a funnel viscosity of 35 - 40 s/litre is obtained. The system is flocculated with small quantities of Lime, Ca(OH)2. The ratio of Bentonite to Lime should be about 35:1.

Bentonite and extended Bentonite systems are also used for land-based drilling, usually when the surface interval is longer than 2 - 3 days. The procedure is to increase and maintain the pH of fresh water at 9 with about 0.75 kg/m3 Caustic Soda. Bentonite is added to the desired funnel viscosity allowing time for hydration. Extending polymers can be mixed with bentonite to increase its yield. The advantages of these systems include: good cleaning and hydraulics, better wall plastering and hole stability, lower solids concentrations and higher ROPs. If the low gravity solids content is kept low enough (less than 150 kgf/m3) then the fluid can be used on the next hole section.



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Offshore, the top of the hole is usually drilled with seawater and high viscosity sweeps. Continuous viscosification becomes expensive since, when drilling without a riser, there are no fluid returns to the rig. Initially, sweeps should be large enough to cover 10-15 m of annulus and they should be pumped every 15 m or so of hole section drilled.

When drilling through permafrost or gas hydrate bearing formations, sweeps should be chilled first. If coolers are not available, viscosifiers should be added to cold seawater just prior to pumping the sweep. It is advantageous and cost effective to use readily dispersible polymers such as Guar Gum or Xanthan Gum.



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When depth increases and hole conditions become more severe, more complex drilling fluids have to be used. According to Eni E&P the various water-based drilling fluids (WBMs) currently available for these more demanding applications are classified in three basic categories:

non-inhibitive water-based drilling fluids (which do not contain chemicals capable to interact with clays and shales);

inhibitive water-based drilling fluids (which, on the contrary, are able to react and inhibit clays and shales);

water-based drilling fluids with low environmental impact.

Water-based muds can be prepared with fresh water (FW) or salt water (SW).

Most of WBMs contain bentonite (called also “gel”) as primary component; therefore all WBMs, more or less markedly, possess viscosifying, fluid loss control and solids suspension and carrying properties. These characteristics can be further improved by addition of specific chemicals.

5.5.1.2.2. WATER-BASED MUDS FOR DEEPER HOLE SECTIONS


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5.5.1.2.2.1. NON-INHIBITIVE WBMs

The drilling fluids systems, which according to Eni E&P classification, constitute the category of non-inhibitive WBMs are the following:

Bentonite-Based Mud (Gel), FW-GE

Guar Gum Suspension, SW-GG

Bentonite-Based Mud with CMC Polymer, FW-GE-PO

Low-Weight (or Low-Solid) Mud with Bentonite Extenders, FW-LW

Lignosulphonate Mud, FW/SW-LS

Chromolignin Mud , FW/SW-CL

PAC Mud, FW/SW-PA

PHPA Mud, FW/SW-PC



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The non-inhibitive WBMs are normally bentonite-based and are by far the most common systems used in drilling. Since their inception in the 1920's, they have been used throughout the world to successfully drill through many types of formations and conditions.

Ongoing research and development have provided a diverse array of proven complementing components and chemicals for these systems. Hence, bentonite-based systems may be modified to address one or several specific drilling fluid functions. These fluids often provide the most economical combination of desired characteristics, imparting good suspension properties and lifting capacity, favourable shear thinning characteristics and good fluid loss and wall building properties.

In a fresh water environment, hydration forces are strong enough to separate natural bentonite aggregates. Separation into individual unit layers is possible. Unit layers are about 10 Å thick and between 100 and 1,000 Å2 wide . The shape of these hydrated platelets imparts resistance to flow or viscosity to a clay suspension. When a shearing force (movement) is applied to a bentonite suspension, the platelets align themselves in a direction parallel to the force. Resistance to flow then decreases, explaining the shear-thinning nature of bentonite suspensions. This thin-flat shape also provides good fluid loss characteristics to the suspension. Because the clay platelets have surface charges, they align themselves to positions of minimum free energy when the suspension is at rest; this accounts for the thixotropic properties exhibited by bentonite suspensions.



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Complementing components for these systems include most of the water-soluble products previously listed.

For best results, fresh water should be used. Excessive salt (>5000 mg/litre) and hardness interfere with the hydration and effectiveness of the bentonite. Soda ash should be used to treat the calcium in the make-up water to less than 40 mg/litre.

The pH should be adjusted to 9.5 - 10.0 prior to adding bentonite. The bentonite should be added slow enough that balling and clogging is eliminated. The initial yield depends in part on the quality of the surface equipment. Normally the slurry becomes thicker with time and agitation.

Usually 60 - 70 kg/m3 of quality bentonite will produce a slurry with a funnel viscosity of 38 - 42 s/litre. This concentration provides a natural fluid loss of approximately 12 - 15 mlitre / 30 min. The yield point of this system should be maintained at a sufficient value to provide effective hole cleaning characteristics and barite suspension with additions of bentonite as required. In an unweighted system, the plastic viscosity value in mPa•s is usually about twice the value of the yield point in Pa. The plastic viscosity (PV) increases as the solids concentration in the system increases. The PV value should be maintained as low as possible by running proper solids control equipment and by dumping and dilution.



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5.5.1.2.2.2. INHIBITIVE WBMs

The inhibitive water-based drilling fluids have been introduced when it was expected to drill through reactive formations (clays and shales, salt) which could cause hole instability problems by reacting with the aqueous phase of the mud.

The first system of this category to be used was a salt saturated drilling fluid; this fluid was developed in the middle 1930's to drill through salt beds and salt domes in the Permian Basin of West Texas and in the Gulf Coast. When extensive salt intervals are penetrated with an undersaturated solution, the salt formation tends to solvate or enter the solution often resulting in severely "washed-out" holes. The poor performance of bentonite in salty environments led to the introduction of attapulgite clays as viscosifiers in 1937. The inferior cake-building characteristics exhibited by these clays resulted in drilling problems including differential sticking and sloughing shale. Starch was soon found to be the most economical material for improving cake characteristics. Salt saturated muds are still in use today, in particular when drilling through salt levels and reactive formations.



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Calcium-based drilling fluids gained widespread use in the Gulf Coast area during the 1940's (Lime, Ca(OH)2 was the source of calcium). Although the reason for their development remains obscure, the most likely explanation is that they exhibited excellent tolerance to anhydrite (CaSO4) contamination, as commonly encountered in East Texas. Gypsum was firstly used in Canada in the 1950's.

Modifications and subsequent development of products to control the system properties have led to a widespread application of calcium-based systems worldwide.

Today calcium systems are still used for their inhibitive properties. The calcium ion provides an economical source of shale hydration inhibition, when used in conjunction with an encapsulator. Systems used for this purpose usually employ Gypsum (CaSO4· 2 H2O), are of low pH and not deflocculated. Calcium-based systems are still often used to drill through evaporate formations containing anhydrite. In this case the system is usually deflocculated, with the pH running about 10.8. Again, Gypsum is usually the source of calcium.



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The primary inhibitive mechanism of these water based systems stems from the ability of the solvated calcium ion to exchange. This occurs with the sodium ion in montmorillonite clays and to a lesser extent the potassium ion in illites. The calcium ion, being divalent, is able to satisfy 1 charge deficiency site on each of 2 clay platelets. In the active fluid this promotes first clay flocculation, then aggregation. This same mechanism inhibits the dispersive, hydration forces in formation clays.

Gypsum-based muds are more common than lime systems today because they are more temperature stable (at temperatures in excess of 130°C a reaction between clays, calcium and hydroxyls can cause a simple cement to form and the drilling fluid can actually solidify). Further, lime systems because of their high pH are less inhibitive than gypsum systems when they are formulated with seawater. This is because the clay inhibition effect normally realized from magnesium, supplied by the seawater, is lost when magnesium is precipitated as magnesium hydroxide, Mg(OH)2 starting at about pH 10. A lime-based system using potassium hydroxide rather than sodium hydroxide is still in use. These systems can work well: it is postulated that the calcium ion stabilizes montmorillonite clays and the potassium ion stabilizes illitic clays. These systems may use a polysaccharide deflocculant derived from starch.



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The effect of the potassium ion on bentonite swelling was first studied in the mid 1950's. It was postulated that potassium has a hydrated diameter, which would favour its exchange for other cations on clay surfaces.

KCl systems gained popularity in the 1970's as a superior method of drilling both mechanically incompetent formations such as highly dipped shales and gumbo or mud making formations. The inhibiting mechanisms of KCl are often augmented with an encapsulating polymer. Polyacrylamide polymers are most often used for this purpose.

Today K-based systems are used, which incorporate non-chloride anions so as to be more environmentally friendly; potassium carbonate (K2CO3), potassium acetate (CH3COOK) or potassium formate (KCOOH) can be used instead of KCl. To make the system completely K-based, K-CMC and K-PAC were developed (by Eni E&P) and KOH is used to control alkalinity and pH.



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Inhibitive water-based drilling systems can be grouped in the following categories:

Salt Saturated Drilling Fluid, FW/SW-SS

Lime-Based Drilling Fluid, FW/SW-LI

Gypsum-Based Drilling Fluid, FW/SW-GY

KCl Drilling Fluid, FW/SW-KC

AgipaK (K-CMC)-Based Drilling Fluid, FW-PK



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5.5.1.2.2.3. INHIBITIVE WBMs WITH LOW ENVIRONMENTAL IMPACT

To meet environmental restrictions some drilling fluid systems have been modified with the introduction in their formulation of chemicals characterized by a lower environmental impact and higher biodegradability or new systems have been developed on purpose.

Among the many types of water-based inhibitive systems, those more commonly used in Eni E&P operations are the following: Potassium Carbonate-Based Fluid, FW-K2 Potassium Acetate-Based Fluid, FW-KA Potassium Formate-Based Fluid, FW-KF Glycol-Based Fluid, FW/SW-GL High Temperatures (>200oC) Water-Based Fluid, FW/SW-HT Cation-Based Fluid, FW/SW-CT Silicate-Based Fluid, FW/SW-SI



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Among these fluids it is worth mentioning the following:

Potassium Carbonate Drilling Fluids: the fluids that contain KCl can pose some problems in case of disposal in onshore operations; in fact, chloride ions, if present in too high concentrations, make the waters resulting from exhausted muds dehydration not conform to the current specifications for discharge in surface water bodies. For this reason, chemicals which always release K+, but not Cl-, are widely used today, such as potassium carbonate, potassium acetate and potassium formate. Substituting KCl with K2CO3 in what are called potassium carbonate drilling fluids gives the following advantages:- CO3

2- ions create less problems in disposal operations and are less corrosive of Cl- ions;- K2CO3 is more soluble in water than KCl, gives more potassium ions and, having a higher pH (>11), does not need additions of KOH and more efficiently neutralizes H2S and CO2 influx.



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Bentonite/PHPA Drilling Fluid: this fluid contains PHPA (partially hydrolyzed polyacrylamides), which provides shale encapsulation. It protects water sensitive shales from hydrating and sloughing into the wellbore.

Glycol-Based Drilling Fluids: many glycols (in particular, the propylene and polyethylene glycols) possess a solubility which is inversely proportional to the temperature; in other words their solubility decreases with increasing temperatures. It happens, therefore, that these glycols are soluble in cold water, but when the solution is heated two phases separate; the polyglycols now appear as small droplets, which can occlude formation pores, preventing water to filtrate and react with water-sensitive formations. The temperature at which the polyglycols separate from the water solution is called “cloud point temperature”. This temperature can be modified as needed, acting on polyglycols concentration, their molecular weight and presence of other compounds, in particular of electrolytes (i.e. NaCl, KCl).



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Cationic Drilling Fluids: these fluids have been proposed around the ‘80’s. These systems are prepared with cationic polymers (instead of the usual anionic polymers) and exploit the fact that clays and shales are predominantly negatively charged (the faces of clay platelets are naturally negative, while the broken edges present both positive and negative charges). The cationic polymers, therefore, should react more promptly with clays and shales than anionic polymers. Though cationic polymers could ensure, at least in theory, a more efficient inhibition of clays with respect to the conventional water-based muds, they are not frequently used because of their toxicity and the incompatibility with most of the usual chemicals. The cationic polymers are low molecular weight polyamines, frequently associated with cationic polyacrylamides. It has been observed that polyamines can prevent clays hydration and swelling by penetrating into the platelets; in some clays, the interlayer space is not wide enough to allow the polyamines penetration, so that a certain initial hydration is required. Cationic polyacrylamides, having a larger size, are adsorbed by electrostatic attraction onto the outer surface of the clays encapsulating them.



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Silicate-Based Drilling Fluids: in the mid-1990’s, there was increasing pressure to find a high performance water-based drilling fluid that would be an environmentally acceptable alternative to oil-based drilling fluids. Known since the 1930’s, after their recent re-introduction in the North Sea, silicate-based drilling fluids have steadily gained in popularity with Service and Oil Companies.

It is generally believed that as the silicate in the mud comes into contact with the slightly acidic (pH 6-8) and multivalent-rich pore water, a localized gellation reaction, coupled with a minor amount of precipitation, takes place to block both the influx of mud and pressure into the formation. These reactions also lead to the sealing of microfractures, cracks and rubble giving a decided advantage over any oil mud, significantly reducing potential mud losses and costs.

Silicates are one of the few oil field chemicals that can be beneficial to the environment. Soluble silicates are derived from, and ultimately return to nature, as silica (SiO2) and soluble sodium and potassium compounds. Since these are among the earth’s most common chemical components, they offer little potential for harmful environmental effects.



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5.5.2. OIL – BASE(D) DRILLING FLUIDS


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In many aspects an oil-based fluid can be described as an ideal fluid because the interactions with the formation are minimal. The main advantages of this situation are that the borehole is stable for an extended period of time and the cuttings can come to the surface solids removal equipment in such a size range that a significant proportion can be removed. This reduces the volume of fluid that is used.

The main feature is a continuous low viscosity oil phase. This reduces the reaction with the polar or water wetting formations. The oil phase also contains solids such as the weighting materials and drilled solids. Again, because of the nonpolar nature of the oil, the viscosity effects of the solids are minimal.

Surfactants are used to make the solids oil wet and, more importantly, to emulsify the brine phase which is added to the oil. The emulsifiers are a special group of chemicals characterized by the presence, in the same molecule, of two contrasting groups, one with strong attractive forces for water and the other attracting strongly to oil. To stabilize inverted emulsions an oil soluble surfactant must be used.

5.5.2.1. MAIN CHARACTERISTICS OF OIL-BASED DRILLING FLUIDS


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The brine phase contains salts to control the activity of the brine preventing it from being drawn from the fluid into the formation. This is a very important factor in formulating an oil-based fluid. It is not just the oil that prevents the water entering the formation, but also the high salinity of the brine phase.

Viscosity control is difficult in oil-based fluids and relies on the use of surfactant treated bentonite. The viscosity mechanism is due to water adsorbed on the clay platelets.

Fluid loss control is very well developed in oil-based fluids and relies on colloidal particles including colloidal sized water droplets and differences in wettability. The fluid loss control may be so well developed that the penetration rate is seriously limited. Therefore, inverted systems can be designed to have high fluid loss characteristics.

Oil-based systems possess properties that are highly desirable and are not obtainable with water-based systems. One of these is the very low level of reaction with the formation, combined with minimal penetration of the fluid phase of the fluid into the formation. This leads to maximum borehole stability over a prolonged time span.



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AdvantagesThe advantages and related benefits of oil-based fluids may be summarized as follows: A maximum level of shale hydration inhibition is realized. A properly conditioned oil mud should have no effect on a shale formation. Therefore, gauge hole can be drilled through water-sensitive shales. This leads to improved cement bonding and reduced cement requirements. Improved log response and better cuttings removal are also beneficially affected. The non-polar environment results in consistent fluid properties, low chemical maintenance costs, stability under high temperature conditions, minimal effects on properties from drilled solids, good resistance to salt and gypsum contamination and good protection of drill string against the corrosive gases H2S and CO2. Formulation for low fluid loss results in low torque, especially in deviated holes, minimized differential sticking problems and low formation damage factors in oil reservoirs. Formulation for high fluid loss results in high rates of penetration. The low solids content and reduction in cuttings stickiness when using oil-based fluids also improves penetration rates. More competent cuttings at surface increase shale shaker efficiency. Oil-based fluids have a higher drilled solids tolerance, which can reduce dilution requirements. Due to their stability and solids tolerance, oil mud can sometimes be used for more than one well. Oil-based fluids have application on wells with bottom hole temperatures up to 300°C. Low aromatic oil-based fluids result in improved rig conditions, low odour, clean handling on the rig, minimal effects on the marine environment, low viscosity imparting improved rheological properties and high flash point giving extra safety. Other advantages include: flexibility with respect to formulation and application, reduced corrosion rates and a reduction in tubular stress fatigue.



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Disadvantages

The disadvantages of oil-based fluids may be summarized as follows:

High make-up cost. Environmental restrictions including cuttings & chemical waste disposal. Extra fire prevention precautions are necessary. Reduced rates of penetration in some areas. Gas intrusion often results in barite settling. Compressibility of the base oil makes volume and density estimations difficult. Hole cleaning and cuttings suspension may be less effective. Rubber materials (such as hoses or BOP components) may dissolve too rapidly in oil-based fluids. Some types of electric logs are ineffective in oil-based fluids. Gas intrusions are more difficult to detect using oil-based fluids. much MORE DIFFICULT KICK DANGER EVALUATION.



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Today the oil-based muds are ordinarily manufactured in two basic types:

Oil-Based Drilling Fluids, in which (theoretically) no water has been added (though, in practice, formulations with up to 10% of water are usually prepared because in this way better rheological and filtration control properties are obtained). Inverted-Emulsion Drilling Fluids, where oil always constitutes the continuous phase but with a content in water, added with salts, varying from 10% up to a maximum of 50%.

Today the type of oil-based mud more frequently used is the Inverted-Emulsion type.

The following list presents some of the situations where inverted emulsion drilling fluids are used:

To drill troublesome shales. To drill deep, hot holes. To drill salt, anhydrite and gypsum zones. To drill and core pay zones. To drill through hydrogen sulphide (H2S) and carbon dioxide (CO2) containing formations. To decrease drill string torque and drag when drilling directional holes. As a packer fluid for corrosion control. As a workover fluid. To minimize the likelihood of differential sticking.



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1. BASE OIL

The liquid phases of an inverted fluid are oil and emulsified water. Solids are contained solely in the oil phase. Generally, the water content does not exceed 50% by volume of the liquid phase. Therefore the properties of the oil greatly influence the overall properties of the fluid.

The essential function of the base oil is to provide a non-polar continuous phase and thus avoid the polar interactions between the drilling fluid and the formation (hydration) that takes place in a water-based fluid. It is important when drilling with an inverted emulsion that all solids, the formation and the drilling equipment be wetted with oil only. Therefore, enough oil must be present in the system to insure that all components are oil wet. Under normal conditions, inverted emulsion drilling fluids containing a minimum of 70% oil should insure proper oil wetting at fluid densities up to 2.20 kg/litre.

Inverted emulsion fluids used for long time diesel oil as it provided stable emulsions at an economical price, but now low toxicity oils are used in place of diesel oil because of their lower environmental impact.

Base oils can be broken down into two categories: synthetics hydrocarbons.

5.5.2.2. INVERTED-EMULSION DRILLING FLUID COMPONENTS


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1. BASE OIL

Synthetics are base oils that are synthesized from other molecules and are generally very pure substances. Chemical industry has to thank so much oil industry!!!!

They include: linear alpha olefins, simply LAO, (C12, C14, C16 or C18) made from ethylene. The double bond is at the beginning of the molecule, in α position; polyalphaolefins, or PAO, derived from the polymerization (dimerization) of linear alpha olefins; isomerized (C12, C14, C16 or C18) or internal olefins, IO, again made from ethylene. They have the same formula but different structure with respect to linear alpha olefins; in fact, the carbon-carbon double bond is randomly isomerized along the carbon chain and can be found in β, γ, δ, etc. positions. This isomerisation drastically affects the viscosity and the pour point of the synthetic oil; esters are typically made from the esterification of vegetable oils with alcohols; isoparaffins are made from paraffinic hydrocarbons by a series of reactions with hydrogen and platinum catalysts. This also decreases the aromatic content of the base oil.



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1. BASE OIL

Hydrocarbon base oils come from refined crude oil feed stocks and are composed by paraffins with a number of carbon atoms from C12 to C18 with the elimination of most aromatic components; they are more frequently used than synthetic base oil because of their lower cost and higher availability.

Hydrocarbon base oils have preferably to possess the following characteristics: high flash point: this is the temperature at which the vapours of the oil can form an explosive mixture with air. Volatile hydrocarbons, such as gasoline, have a flash point as low as 5oC. For the base oil used in OBMs preparation a flash point > 61oC is normally required; high fire point: it is the temperature at which the vapours ignite and burn. Values above 93oC are preferred though this parameter is not so critical in the OBMs manufacturing; high bubble point: it represents the temperature at which the oil starts boiling; an oil with a low bubble point will produce more vapours than an oil with a high bubble point; high aniline point: it is the temperature at which a homogeneous mixture of aromatic compounds is completely solubilised in a given volume of aniline. It indicates the tendency of an oil to degrade elastomers: lower is the aniline point higher will the tendency of the oil to attack the elastomeric components of drilling equipments low content in aromatic components.



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2. BRINE PHASE

The brine phase contributes to the rheological and filtration properties of the drilling fluid. The inclusion of a brine or water phase in an inverted emulsion ensures that desirable non-Newtonian properties are incorporated into the drilling fluid.

An important aspect of the brine phase is referred to as "activity". The term activity, in a drilling sense, describes the tendency for the movement of water vapour from an area of low salt concentration to an area of high salinity. The water activity (Aw) is measured as a fraction of the vapour pressure of water or relative humidity.

In an inverted emulsion drilling fluid the brine phase is not isolated from the formation by the oil phase. Water vapour may pass from the brine droplet into the formation or vice-versa depending upon the osmotic pressure differential between the brine phase and the formation. The concentration of salt in the brine phase will largely determine whether water will flow from the brine to the formation, from the formation into the brine phase or whether there will be no net movement of water in either directions.

The ideal practice would be to have balanced activities between the formation water and the drilling fluid brine phase. A balanced activity would mean that no net water migration between the formation and brine phase would occur. The desirable balanced activity condition may not always be possible during the drilling process since formation activities can be variable. In practice, the brine phase is often run with a lower Aw value (higher salt concentration) than the values expected in the formation. This results in a small net movement of water vapour from the formation into the drilling fluid.



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3. EMULSIFIERS

Preparation of a stable water-in-oil emulsion is dependent upon two factors: the size of the brine droplets and the efficiency of emulsifiers that produce and maintain the emulsion. Smaller water or brine droplets are produced at higher rates of mixing or shear with a more stable, tighter emulsion resulting. A tighter emulsion is generally more viscous than a less stable emulsion. The smaller brine droplets in a tight emulsion are less likely to coalesce when they collide than larger droplets. It is the function of the emulsifiers to isolate the brine droplets and prevent any coalescence. Emulsifiers are also important in ensuring that solids in the inverted emulsion are preferentially wetted by the continuous oil phase. Without oil wetting characteristics, the solids, especially barite, would become water wet and the overall result would be poor emulsion stability.

inverted systems use a blend of emulsifiers formulated to ensure emulsion stability for any brine at a range of brine concentrations. The primary emulsifier is an alkyl fatty acid emulsifier. Addition of lime to the primary emulsifier converts an "inactive" emulsifier into its "active" or working form. The hydrophilic portion of the active emulsifier form is intimately associated with the brine droplet at the oil-brine interface, while the hydrophobic portion of the emulsifier is dissolved in the continuous oil phase.

In addition to the primary emulsifier other emulsifiers called secondary emulsifiers are required to produce a stable inverted emulsion for inverted drilling fluids. They usually contain OH, NH2 and CONH2 functions that associate with the brine phase, being hydrophilic.



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4. VISCOSIFIERS

The viscous properties of an inverted emulsion fluid are developed by: oil, emulsified water, oil wetted solids (weighting agents such as barite and drilled solids) and specially processed bentonite treated with quaternary amines (organoclays). Thus the viscous properties are determined to a significant degree by the oil/water ratio and the fluid density. The level of viscosifier required will be decreased by an increase in density and water content.

The major contribution to non-Newtonian rheology is derived from organoclays. These are bentonites in which the inorganic exchangeable cations sodium, calcium and magnesium have been displaced by quaternary amines such as dimethyl, di (hydrogenated tallow) ammonium chloride or dimethyl, benzyl, ammonium chloride. These cationic surfactants change the wetting character of the bentonite from being water wettable to being oil wettable.

The viscosity properties have to be developed by the dispersion of the stacks of clay platelets. This is achieved to some extent by mechanical factors such as shear intensity, shear time and temperatures.

Polar compounds such as the aromatic molecules in diesel oil or water also play an important role. Adsorption of these molecules opens up the sheets and aids the dispersion process. Water is required to create the conductive medium in which ionic bonds and other polar interactions can develop between the clay platelets.



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5. FLUID LOSS CONTROL ADDITIVES

inverted emulsion drilling fluids typically have small fluid loss values under HT-HP conditions. There are a number of reasons for the low fluid loss values. When the inverted fluid contained in the annulus contacts the formation walls there is a small initial loss of oil to the formation. The brine phase then acts as an impermeable membrane along the formation walls to retard the movement of oil into the formation. In addition, the oil phase of inverted fluids does not readily enter the water-wet formations due to a high interfacial tension between the oil and formation water.

In addition to the filtration control imparted by the oil and brine phases of inverted emulsions, inverted systems employ supplemental fluid loss control materials. These materials are high temperature stable and oil dispersible. Asphaltic bitumen is the most common fluid loss additive used. Amine treated lignite may be used in the place of asphaltic bitumen.

Relaxed oil muds have been designed for fast drilling, with a HP-HT fluid loss as high as can be tolerated. A relaxed oil mud has the same chemical composition as an ordinary oil-based fluid. The difference being that the former fluid system is run on the borderline between functioning and breaking down. To relax an oil mud and increase the fluid loss, base oil, CaCl2 brine or water must be added to the mud without the usual additions of emulsifiers, oil wetting agents, etc. The additions of the emulsifiers would change the mud system back towards a stable system. Relaxed oil muds require rigorous pilot testing and continuous monitoring. In order to relax a conventional oil mud, large increases in volume have to be expected due to the amount of dilution that is required.



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Among the various types of oil-based drilling fluids, the most common in Eni E&P use are shown below:

Diesel Oil Inverted-Emulsion Drilling Fluid, DS-IE Diesel Oil Inverted-Emulsion Relaxed Filtrate Drilling Fluid, DS-IE-RF 100% Oil-Based Drilling Fluid, DS/LT-IE-100 Low Toxicity Mineral Oil, Inverted-Emulsion Drilling Fluid, LT-IE 50/50 O/W Inverted-Emulsion Drilling Fluid, LT-IE-50 Ester-Based Inverted-Emulsion Drilling Fluid, EB-IE Linear Paraffin-Based Inverted-Emulsion Drilling Fluid, LP-IE

Large amounts of alternative solutions are still now under study and validation.

It is worth recalling that the diesel oil based fluids are not in use today, since they have been replaced during the last decade by low toxicity base oils.

5.5.2.3. TYPES OF OIL-BASED DRILLING FLUIDS


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5.5.3. GAS - BASE(D) DRILLING FLUIDS


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Low density fluids are sometimes called gas-based or reduced pressure drilling fluids. The original purpose of these fluids was either to avoid loss of circulation or reduce the amount of water lost into production zones. Improved rates of penetration and longer bit life soon became well-known secondary benefits.

These systems can be classified as follows:

Gas or Air

Mist / Foam

Stiff / Stable Foam

Aerated Drilling Fluids

5.5.3.1. TYPES OF GAS-BASED DRILLING FLUIDS


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Dry gas drilling was first patented in 1866 and is still used in many areas today. When drilling with gas or air, enough volume must be supplied to generate annular velocities in the range of 900 m/min. Care must be taken to avoid the risk of downhole fires and explosions.

The injection into a gas of small amounts of drilling fluid or water containing a foaming surfactant results in a mist or foam drilling fluid. The foaming surfactant mixes with the formation water. This increases carrying capacity, permitting the removal of water from the hole at lower annular velocities.

A stable foam is obtained by mixing: water, soda ash, bentonite, guar gum and a foaming agent. Stiff foam fluids have the consistency of shaving cream. They are used when: an air drilling operation encounters a water flow, for clean out and remedial jobs.

Aerated drilling fluids were first used in 1953 and various systems have been used to inject air into the drilling fluid thus reducing hydrostatic head, such as: injecting air into the standpipe or into the annulus, using a dual drill string-one within the other.

5.5.3.1. TYPES OF GAS-BASED DRILLING FLUIDS


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5.6. BASIC RHEOLOGY OF DRILLING FLUIDS


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The fluids can be classified in two main rheological classes:

Newtonian fluids

non-Newtonian fluids

1. NEWTONIAN FLUIDSThe fluids, which follow Newton law, are defined as “Newtonian fluids”. For these fluids, at constant pressure and temperature, the shear stress is directly proportional to the shear rate. They start moving as soon as a stress, slightly above zero, is applied to them. In a “shear rate - shear stress” diagram, the movement of these fluids is represented by a straight line passing through the origin of the Cartesian axes, whose slope is proportional to a quantity called “viscosity”; viscosity, at given temperature and pressure conditions, is constant and independent by the shear stress.


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Constant Slope

Shear Rate (y) (rpm or 1/s elsewhere)

She

ar s

t ress

Viscosity describes completely the behaviour of a Newtonian fluid and is expressed by the following equation:

μ = τ / γ

where:

• μ = dynamic viscosity• τ = shear stress• γ = shear rate

Newtonian fluids are: water, glycerine, (and, approximating, also diesel oil, gas).



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2. NON-NEWTONIAN FLUIDS

The fluids, which do not follow the Newton law, are called “non-Newtonian fluids”, dueto the fact that they do not exhibit a direct proportionality between shear rate and shearstress. The shear stress, in fact, changes as the shear rate changes; for this reasonthe ratio “shear stress/shear rate” is indicated as “apparent viscosity”.

The non-Newtonian fluids are classified in four main categories:

1) Fluids whose properties are independent by the time.

2) Fluids whose properties are dependent by the time.

3) Fluids with characteristics which are very similar to solid bodies.

4) Complex fluids.



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1) Fluids whose properties are time independent

These fluids are subdivisible in three classes: a) Bingham plastic fluidsb) Pseudoplastic fluids & Dilatant fluidsc) Yield pseudoplastic fluids

a) Bingham plastic fluids The Bingham plastic fluids, on the “shear stress/shear rate” graph, are

represented by a straight line, which is not passing for the origin of the Cartesian axes. This means that for starting their flow, it is necessary to apply to them a given shear stress, whose value is known as “yield value” and its position on the Y-axis as “yield point”.

The behaviour of a Bingham plastic fluid is described by the following equation:

τ = YV + μp ٠ γ being τ > YVwhere:- μp = straight line slope, known as “plastic viscosity” PV (while: YV = τ0 )



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Examples of Bingham plastic fluids are: some aqueous suspensions of rocks, slurries of dirty waters.



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b.1) Pseudoplastic fluidsThe pseudoplastic fluids are characterized by a curve passing through the origin of the Cartesian axes and their behaviour is represented by the following relation, known as “Power Law” or “Ostwald & De Waele model”:

τ = K ( γ )n being n < 1where:- K = flow consistency index- n = flow behaviour index

The term “n” shows of how much the behaviour of the fluid under consideration departs from a Newtonian fluid; in fact: if n = 1 the fluid is Newtonian and the equation becomes that of a Newtonian fluid with the term K corresponding to the viscosity; if n ≠ 1, as more n differs from 1 more non-Newtonian is the fluid behaviour; in particular:

- when n<1, as in this case, the fluid is called pseudoplastic; - when n>1 the fluid is said having a dilatant behaviour

The term K is similar to the viscosity; higher K, higher will be the viscosity of the fluid.



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The apparent viscosity of a pseudoplastic fluid decreases with increasing shear rates.

Examples of pseudoplastic fluids are: solutions or fusions of polymers, paper paste suspensions, pigments.



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b.2) Dilatant fluidsThe behaviour of a dilatant fluid is, in practice, the opposite of that of pseudoplastic fluids. They are described by the same power law with the only difference, that in this case n>1:

τ = K ( γ )n being n > 1where:- K = flow consistency index- n = flow behaviour index

In this case, as already pointed out, the apparent viscosity increases with increasing shear.

Dilatant fluids are: aqueous suspensions of starch and mica, shifting sands, beach sands.



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c) Yield pseudoplastic fluidsYield pseudoplastic fluids have a yield point and apparent viscosity which have no linear relationship with the shear rate, as already observed for pseudoplastic fluids. In these fluids, the apparent viscosity decreases as the shear rate values increase; the inclination of the flow curve, instead, continually decreases and very often tends to a constant value at high shear rates. The rheological behaviour of a yield dilatant fluid is the opposite to that of a yield pseudoplastic fluid, because its apparent viscosity increases with increasing shear rates.

The theoretical model which represents in the best way the behaviour of these fluids was conceived by Herschel - Bulkley, at the beginning of 1900 to simulate the behaviour of rubber and benzene solutions. This model is expressed by this equation

τ = τo + K ( γ )n being n < 1where:- K = flow consistency index- n = flow behaviour index- τo = yield point or yield stress



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Again, K indicates the degree of fluid viscosity and, at times, is analogous to the apparent viscosity, while n always represents the difference from a Newtonian fluid behaviour.



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2) Fluids with time-dependent properties

There are many fluids, whose behaviour can not be represented by the models seen previously for non Newtonian time-independent fluids. The apparent viscosity of the non Newtonian time-dependent fluids is not only a function of shear rates, but also by the time the stress is acting on them.

These fluids can be grouped in two categories:

Thixotropic fluids

Rheopectic fluids



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a) Thixotropic fluidsThe thixotropic fluids possess a structure whose breakage depends both by time and by shear rate. Maintaining a constant shear rate, the shear stress decreases as soon as the structure of the fluids starts breaking. The structurization of the fluid restarts when the stress is removed, unless other external forces act on the system. The extent of the DEAFD area is an indication of the thixotropy entity. If we maintain constant the shear rate after Point A, the shear stress decreases along with the AC straight line till the Point C is reached. No other failure of the structure occur after this Point C for that given shear rate. If the shear rate is decreased, the corresponding shear stress follows the path of the curve CHD, where the Point D is the initial yield point; but to come back again to the Point D infinite curves can be followed depending on particular circumstances.

Examples of these fluids are: drilling muds, paints, inks.



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b) Rheopectic fluidsThe fluids of this category tend to build up a structure when they flow at low share rates; in these conditions, their apparent viscosity increases with increasing shear rates. But when a certain critical shear rate value is surpassed, their structure is destroyed and, consequently, their apparent viscosity starts to decrease with increasing shear rates. Rheopectic fluids are: bentonite suspension in sol state, gypsum in water suspensions.

3. Viscoelastic fluidsThe viscoelastic fluids exhibit elastic and viscous characteristics: they, up to a certain extent, are capable to deform elastically. Examples are: some liquid polymers, pitch.

4. Complex fluidsThere are many fluids which do not belong to any of the categories mentioned up to now, because their shear rate/shear stress relationship can not be described by a simple mathematical equation. A modern drilling mud, due to its high compositional complexity and the different behaviours it exhibits under varying temperature, time, shear rate regimes, can be classified as a typical complex fluid.



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MODELLING A DRILLING MUD

For what said up to now, it is evident that there is not only one model capable of representing the wide variety of drilling mud formulations and the consequent very different behaviour of these very complex systems.

In many cases, for sake of simplicity, the Bingham plastic fluid model is preferred in particular when calculations have to be made by hand or when the equation have to be transformed into graphs; in other circumstances the Ostwald & De Waele model of the power law is adopted and in other situations the Herschel & Bulkley model. But many other models, some very complex from a mathematical point of view, could be used to represent a mud.

The choice of the model depends on its capacity to better interpolate the experimental rheological values as obtained, for instance, by the Fann rotational viscometer (which is the equipment widely used in the Oil Industry for the rheological characterization of a drilling mud), on the evaluation if it is worth to use a complex model without obtaining an evident improvement on pressure losses calculation in the hydraulic circuit of a rig and its easiness of use.



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CALCULATION OF THE RHEOLOGICAL PARAMETERS OF A DRILLING FLUID

1. BINGHAM PLASTIC FLUID MODEL

- Plastic viscosity:

- Yield point:

/2 [gf/100 cm2]



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2. OSTWALD & DE WAELE PSEUDOPLASTIC FLUID (POWER LAW) MODEL

- Flow behaviour index, n:

- Flow consistency index, k:

[ ]



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3. HERSCHEL&BULKLEY YIELD PSEUDOPLASTIC FLUID MODEL

- Yield point, τo:

- Flow behaviour index, n:

- Flow consistency index, k:


05.Politecnico Di Torino Drilling Fluids Programme 2011

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