Perspective Chapter: Main Characteristics and Rheological Properties of Drilling Fluids

Abstract

This chapter includes the main characteristics and rheological and thixotropic properties of drilling fluids. The drilling fluid is composed of a liquid phase and a solid phase. The rheological properties characterize the flow behavior of the drilling fluids, including the resistance to displacement of some bodies in the fluid mass. These properties allow to evaluate the pressure and pumping energy of the drilling fluids, the washing conditions as well as the evacuation of the detritus, the danger of erosion of the walls. To describe the behavior of rheological fluids, we use the Bingham and Ostwald de Waele models.

1. Introduction

In hydraulic rotary drilling, washing the sole of detritus and bringing it to the surface is achieved by the circulation of a drilling fluid in the well.

When there are no possible complications in the drilling, caused by the nature of the geological formations crossed, water itself can be used as the circulation fluid. In the vast majority of cases, however, the drilling fluid (mud) is used as a circulation agent [1].

The drilling fluid is a polydisperse colloidal system composed of two phases:

1. the liquid phase, (consisting of water or petroleum product) in which different additives such as lignosulfonates, humates, phosphates, sodium hydroxide, etc. are dispersed;

2. the solid (dispersed) phase composed of certain types of clays and weighting materials. Figure 1 shows the circuit diagram of the drilling fluid. The component parts are:

Figure 1.

Flow diagram of drilling fluid.

1—drilling mud battle; 2—circulation pump; 3—hydraulic head; 4—set of drilling rods; 5—drill bit; 6—downspout column; 7—double flange; 8—the device for total closure of the probe; 9—the device for closing the annular space; 10—teu for drilling mud evacuation; 11—adjustable nozzle; 12—valve for reverse circulation; 13—hydraulic head channel.

The main functions that a drilling fluid must fulfill are:

1. to ensure the perfect cleaning of the sole of detritus and its transport to the surface. For this, the fluidity of the circulation agent must be as high as possible, and its flow must be appropriate (v_as = 0.6…1.4 m/s). On the other hand, the carrying capacity of the drilling fluid increases as its viscosity increases. That is why in practice, when high flow rates can be achieved, fluids with the lowest possible viscosities are used. When the flow rate is low, the viscosity of the fluid must be increased, taking into account, of course, the dimensions and specific weight of the detritus.

2. when the circulation is interrupted, ensure that the detritus is kept in suspension, avoiding the sticking of the drilling gasket due to its deposit on the sole, and the resumption of circulation does not require the development of exaggerated pressures at the pumps. For this, the fluid must have good thixotropic properties.

3. to deposit on the walls of the well a clogging crust (cake) as thin as possible, compact, resistant and impermeable to ensure the stability of the walls and minimize the amount of filtered water around the well.

4. to ensure a sufficient counterpressure on the layers containing fluids under pressure (to prevent possible manifestations or eruptions) and on the walls of the well (to avoid their collapse). These functions depend on the density of the drilling fluid.

5. to achieve a good cooling of the hoe—when drilling with a mass—of the gasket, as well as the lubrication of the roller hoe bearings.

6. to allow the realization of the best electrical coring. Salty muds, due to their very high electrical conductivity, cause partial short-circuiting of the electrodes, while black fluids—which have a high resistivity—the electrical connection of the electrodes with the well walls is very reduced. In such cases, new coring methods must be used: microlog, laterolog, microlaterolog, inductive, etc.

7. to allow the rapid and complete separation of the detritus on the surface. This depends on the viscosity and gelation of the fluid, which must not have too high values, as well as on the construction of the external cleaning system.

8. other conditions required of a drilling fluid are the following:

   • to be easy to condition and maintain;

   • to be easily pumpable;

   • to ensure the appropriate opening of productive horizons and their putting into production without difficulties [2, 3, 4, 5, 6, 7].

2. Classification of drilling fluids

Currently, a great diversity of fluids is used, the appearance of which is stimulated by the expansion of drilling at depth and in increasingly difficult geological conditions, the efforts to improve the drilling performance and the conditions for traversing the productive strata. Their study calls for a classification that is coherent but flexible enough to encompass the new types of prepared fluids [3, 4, 5].

The existing classifications are based on various criteria such as:

1. state of aggregation: liquids, gases, aerated liquids, fog, foam;

2. the nature of the dispersion phase: water-based, oil-based, gaseous;

3. the nature of the dispersed phase: with clay, with polymers, with organophilic clays, with asphalt;

4. degree of mineralization: with low, medium or high mineralization;

5. nature of mineralization: salty, with lime, with gypsum, with calcium chloride, with potassium chloride, with potassium, with potassium and lime, etc.;

6. density: light (unweighted) and weighted;

7. pH value: with high alkalinity (over 11.5), medium (between 8 and 11.5), weakly alkaline (between 7 and 8.5), neutral (around 7), acidic (below 7);

8. method of preparation: from water with dislocated rock, prepared on the surface;

9. degree of dispersion: dispersed, inhibitory (non-dispersed);

10. destination: for the actual drilling, the opening of productive layers, fluids for release, packer, perforation, killing.

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3. Types of drilling fluids

3.1 Dispersed (classic) drilling fluids

These fluids are based on the water-clay system (diluted solution with betonite in water with a density of 1040…1060 kg/m³) and therefore meet the stability, clogging and gelling requirements necessary for drilling. Prepared on the surface from bentonite clays with good colloidal and dispersive properties, these fluids are used for drilling surface intervals or areas with loss of circulation where, as a rule, mud with high viscosity and gelation, without other special properties, is required [6, 7, 8, 9, 10, 11, 12, 13, 14].

In case of crossing clayey rocks that disperse or swell, productive strata or when the preparation clay does not provide the desired structural properties, these muds are treated with reduced amounts of fluidizers, filter reducers, stabilizers of the properties at high temperatures or at the action contaminated, lubricants, antifoams, becoming treated mud. During the contact with the aqueous phase of the fluid, the clayey walls of the borehole lose stability or the mud becomes heavily contaminated, which can lead to frequent, expensive and beyond certain ineffective treatments, which is why their field of applicability is often reduced to simple geological conditions.

The clogging cake deposited by such a drilling fluid is chemically insoluble (in acid solutions), and the non-inhibitory filtrate can lead to the dispersion of clay minerals contained in the reservoir rock matrix.

3.2 Inhibitive drilling fluids

The fluids in this category are based on the whole water-clay system, but having a main role in ensuring the stability of the system and imprinting a strong inhibitory character on the aqueous environment, it is fulfilled by the addition of electrolytes, protective polymers, surfactants, certain fluidizers, etc.

Inhibitive drilling fluids prevent or delay the hydration, swelling and dispersion of clay rocks and at the same time show high inertia to classic contaminants such as clays, electrolytes and high temperatures. They are used when traversing thick intervals of marls and clays sensitive to water, to reduce drilling difficulties generated by rock-fluid contact, when opening productive layers with clay intercalations (dirt). In general, the main disadvantage of inhibitory drilling fluids is, moreover, as with dispersed drilling fluids, the failure to meet the criterion of chemical solubility of the system additives.

The clogging cake deposited by such a drilling fluid is chemically insoluble (in acid or oxidant solutions).

3.3 Salt-based fluids

Fluids with sodium chloride have inhibition capacity, through their flocculant and aggregation effect. Salty fluids are those that have more than 1 g NaCl/100 cm³ filtered and they can be born by contaminating the fresh muds with dissolved salt from the traversed rocks or with the water penetrated from the layers in the well, by using sea water in their preparation or by the intentional addition of salt.

The inhibitory capacity of salt-based fluids depends on the concentration of NaCl and the presence of deflocculant fluidizers, but, in general, they are corrosive, foam, affect electrical resistivity coring, and salt diminishes the effect of fluidizing additives, antifilters and emulsifiers. Initially, fluids with NaCl were used to drill through thick packages of salt and clay, but over time it was found that salty muds have a good inhibitory capacity for many categories of clays encountered during drilling.

In the practice of well drilling, fluids with NaCl are prepared in the following variants:

• unsaturated salty fluids (1…5% NaCl);

• saturated salty fluids (>30% NaCl);

• semi-saturated salty fluids (10–15% NaCl).

Another advantage of a NaCl-based fluid is the simplification of top-up methods. The clogging cake (consisting mainly of medium and coarse NaCl) is easy to remove by simply washing with unsaturated solutions. Another variant of the same drilling fluid is the use of specially granulated sodium chloride as a bridging material (the size of the sodium chloride granules is determined according to the size of the pores of the traversed formation).

3.4 Polymer-based fluids

In general, polymers based on organic compounds are used, but also inorganic flocculants (NaCl, lime, gypsum). The polymers can be of the cationic type, acting through their strongly positively charged hydrophilic chain, or of the anionic or non-ionic type, accompanied by an electrolyte to neutralize the electrical charges of the clay plates.

From the many practical observations and laboratory studies it was found that the nature and properties of the drilling fluids greatly affect the speed of advancement of the hoe and the yardage achieved by it.

In the well, the inhibiting effect of the polymers is due to the formation of a protective film that prevents the penetration of water, swelling and dispersion of clays.

According to the functions they perform in the fluid, polymers can be classified as follows:

• complex flocculants—which flocculate both bentonite and detritus particles;

• selective flocculants—which only flocculate the drilled solids;

• flocculants with double action—which flocculate the drilled solids, but at the same time improve the yield of the bentonite.

The main disadvantage of polymer-based drilling fluids is the failure to meet the criterion of chemical solubility of system additives. The clogging cake deposited by such a drilling fluid is chemically insoluble (in acid or oxidant solutions).

3.5 Fluids based on petroleum products

These fluids are dispersed systems whose continuous phase is a petroleum product, mineral oil or a synthetic fluid, in which the additives necessary to create the structure and clogging properties are dispersed and dissolved, as well as a quantity of emulsified water, added to regulate certain properties.

The main variants of fluids based on petroleum products are the following:

• with low water content also called black fluids with 3….10% water;

• inverse emulsions 10….60% water; The specific properties of these fluids are:

• filtered reduced and consisting only of petroleum product, mineral oil or synthetic fluid;

• inertia to contaminations such as marl, clay, salt, gypsum, anhydrite, cement;

• resistance to high temperatures;

• increased stability in temperature conditions and even during long storage;

• high lubrication capacity.

Due to these properties, fluids based on petroleum products/mineral oil/synthetic fluids can be used for:

• crossing rocks with water-sensitive clay minerals, salt masses, gypsum, anhydrite, potassium salts, formations with hydrogen sulphide and carbon dioxide;

• the drilling of deep and hot wells;

• the opening of the productive layers, especially those with low pressure, because their filtrate is smaller and consists of petroleum product/mineral oil/synthetic fluid and allow, in terms of density, a drilling close to the layer-well balance;

• drilling and coring of unconsolidated sands and productive layers with clay particles;

• the reactivation of some old wells;

• release of stuck gaskets, such as packer and perforating fluids.

Establishing the emulsion involves the use of various calcium or sodium fatty acid soaps, especially naphthenic acids, as well as some metallic soaps as emulsifiers. Most of the times, the saponification of acids takes place in the emulsification process: the added fatty acids and naphthenic acids in the composition of the oil react with the calcium or sodium hydroxide dissolved in the preparation water. The calcium soap stabilizes the water-in-oil emulsion, and the sodium soap forms bonds between the two phases.

Since inverse emulsion fluids are used to solve difficult problems related to the drilling and production of productive layers, and the instability of the borehole is attributed to clay rocks and the fact that they change their properties in contact with aqueous media, inverse emulsions are made with controlled chemical activity. By regulating the activity of the aqueous phase in the reverse emulsion with electrolytes, the invasion of water into the clay rocks can be prevented and in this way better stability of the wellbore is ensured.

The main disadvantage of these systems when traversing the productive formations by drilling is the high potential of changing the natural humidity of the reservoir rock. In the well completion phase, washing with solvents is also needed, an operation that often leads to the formation of microemulsions and pronounced blockages of the productive formation.

3.6 Clear fluids

In general, these fluids or salt solutions can be used in consolidated formations that are not affected by the penetration of large volumes of fluid into the porous-permeable rock. These non-viscous fluids can be used in fractured calcareous or dolomitic formations or in formations originating from coral accumulations and sometimes, but with reservations, in fractured sandstones without interstitial clay. These fluids require turbulent flow and viscous cleanout plugs to effectively direct the detritus out of the borehole. Viscous plugs must be made without the addition of bentonite, only based on biopolymers (xanthan gum) or HEC (hydroxyethyl cellulose).

Flocculants can be used in the surface cleaning system to keep the fluid clear and precipitate solids entrained during the drilling process. With this type of drilling fluid, completion operations are carried out in open hole or perforated liner.

4. The rheological properties of drilling fluids

The rheological properties characterize the flow behavior of the drilling fluids, including the resistance to movement of some bodies in the fluid mass. These properties allow to evaluate the pressure and pumping energy of the drilling fluids, the washing conditions as well as the evacuation of the detritus, the danger of erosion of the walls.

In general, the flow behavior of fluids, but also of systems with a continuous fluid phase, is described by a series of mathematical models, which can also be called constitutive equations, flow laws or rheological models. The mathematical models express the relationship between the tangential stresses τ, which can arise between a moving fluid and the deformation (shear) velocities dv/dx, in laminar flow regime. Thus, the quantities τ and dv/dx represent the rheological variability, and the scalar parameters represent the rheological constants of the respective equations.

Their values are obtained by processing the measurable quantities specific to each type of viscometer, such as, for example, flow rate and pressure drop (for tubular viscometers) or speed and tension moment (for viscometers with coaxial cylinders). Diagrams τ = f (dv/dx) are called rheograms.

(a) Newtonian fluids (their category includes water, petroleum products, electrolyte solutions and other single-phase liquids with low molar mass) have the following constitutive equation:

$$\tau ={\eta }_d\frac{d\nu }{dx}$$E1

The rheograms of these Newtonian fluids (Figure 2) are generally straight that pass through the origin, their slope itself representing the rheological constant, i.e. the so-called dynamic or absolute viscosity.

Figure 2.

Rheogram Newton model.

$$tg\alpha =\frac{\tau }{\left(d\nu /dx\right)}$$E2

Having a heterogeneous structure, the drilling fluids do not obey the Newtonian flow law, and the viscosity is no longer constant. Thus, the viscosity depends on the shear rate and is called the apparent viscosity.

Drilling fluid and cement pastes can be described with sufficient precision by the following rheological models: Bingham and Ostwald de Waele.

(b) Bingham-type fluids (which include dispersed muds with high clay content and high density, as well as poorly treated cement pastes) have the following constitutive equation:

$$\tau ={\tau }_0+{\eta }_{pl}\frac{d\nu }{dx}$$E3

The rheograms of these fluids are straight with the origin ordinate τ₀ (Figure 3). Rheograms still have and two rheological constants:

Figure 3.

Bingham model rheogram.

${\eta }_{pl}$—plastic (structural) viscosity.

τ₀—dynamic shear stress.

Moreover, it is worth noting that ${\eta }_{pl}$ represents the slope of the right

$${\eta }_{pl}=tg\beta =\frac{\tau -{\tau }_0}{d\nu /dx}$$E4

and from a physical point of view it is a measure of the internal frictions in the system, respectively between the molecules of the dispersion medium but also between its molecules and the particles of the dispersed phases, as well as the particles arranged between them. Thus ${\eta }_{pl}$ it gives indications on the total content of solids in the system.

Since τ₀ is an additional resistance it must be overcome during the flow, to prevent the tendency of other dispersed particles in the system to form structure. In the case of drilling muds, τ₀ gives indications on the content of bentonite clay.

(c) Oswald de Waele type fluids (which include drilling fluids with a low content of clay solids and flocculant polymers, fluids based on petroleum products and highly treated cement pastes) have the following constitutive equation:

$$\tau =k{\left(\frac{d\nu }{dx}\right)}^n$$E5

The fluid rheogram is a power curve (Figure 4), the rheological modules being: K—consistency index, n—behavior index.

Figure 4.

Rheogram Ostwald de Waele model.

In general, the consistency index K increases with the content of dispersed particles. After numerous researches, it was found that the parameter K increases when the mud is flocculated, and the behavior index n moves away from unity. Typically n < 1 for most drilling fluids and cement pastes.

All fluids that do not obey Newton’s law fall into the category of non-Newtonian fluids. Characteristic of these fluids is the fact that their apparent viscosity is no longer constant, but changes depending on the rate of deformation.

For Binghamian and Ostwaldian fluids we have:

$${\eta }_{ap}=\frac{\tau }{d\nu /dx}={\eta }_{pl}\frac{{\tau }_0}{d\nu /dx}$$E6

$${\eta }_{ap}=\frac{\tau }{d\nu /dx}=K{\left(d\nu /dx\right)}^{n-1}$$E7

They confirm the dependence of the apparent viscosity both on the deformation rate and on the rheological parameters.

5. Thixotropic properties of drilling fluids

In general, thixotropy can be understood as the gelation of a solution when it is left at rest and the return of the gel to the solution by stirring. This phenomenon is specific to colloidal solutions, in which the dispersed particles are ionized.

Gelation usually occurs rapidly, but eventually the rate slows down, and the process often continues for several hours, days, or even months. In Figure 5 are presented characteristic curves that allow the appreciation, by comparison, of the formation properties of the gel structure for some typical muds.

Figure 5.

Characteristic curves of gelation of drilling fluids.

The static shear stress corresponding to generally very weak gels has a lower limit of 1.5…2 N/m², while the upper limit, specific to strong gels, is between 15…20 N/m². Most of the drilling fluids with thixotropic properties have the ability to maintain in suspension the inert weighting materials and detritus, a characteristic that is especially necessary in case of stopping the circulation in the well. High values of thixotropy (high gels and fast gelation speeds) often cause difficulties in cleaning the drilling fluid [5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15].

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6. Conclusion

Drilling fluids consist of two phases: a liquid phase and a solid phase. The main types of drilling fluids are: dispersed (classic) drilling fluids, inhibitory drilling fluids, salt-based fluids, polymer-based fluids, petroleum-based fluids and clear fluids. The rheological properties of the drilling fluids are described using the Bingham and Ostwald de Waele models.