Introduction and Basic Concepts of (Drilling) - Part2

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Chemical Inhibition

The consolidation process and the overburden pressure forces water out of the shales. Relief of the confining force and re-exposure to water causes the water to adsorb very strongly onto the clay surfaces. The following changes also occur. 


• Stress increases around the wellbore. 
• The shale swells and weakens. 
• Lubrication is provided for slippage planes.
• Plastic shales deform into wellbore, giving tight hole conditions. 
• Harder shales generate cavings. 
• Time related instability occurs as water migrates into rock.

These changes in rock properties inevitably result in many problems, including:
• Hole failure 
• Tight hole 
• Washed out hole 
• Reaming 
• Stuck pipe due to hole collapse 
• Dispersion of solids into mud 
• Additional solids into the mud 
• More solids to be removed at surface 
• Poor annular rates in washed out hole 
• Bit balling 
• Poor directional control

The magnitude of this problem depends on 
• Type of formation – Shales with montmorillonite or mixed layer clays are susceptible. 
• Type of drilling fluid – Fresh water is most reactive.

A lot of effort has gone into designing mud systems with “inhibition” or increased ability to minimize the reaction between the mud and the shales. The approach is to change the exchangeable cation or to expel water from the clay surface.

• Exchange sodium ion for calcium
• Exchange sodium and calcium for potassium
• Exchange sodium and calcium for low molecular weight cationic polymers
• Adsorb high molecular weight polymers to coat clays and displace water (PHPA)
• Add polyglycerol to displace water
• Plug fractures with asphalt and gilsonite

Specific mud formulations and products are detailed in Module LAB203.03 on Water-based Drilling Fluids.

The problem with the reaction of the shale with water can be eliminated by formulating the drilling fluid with oil. The adsorption forces are so well developed that high levels of salt have to be dissolved in the water, which is present as an emulsion, to prevent the shale from hydrating. Module LAB203.05 on Oil-based Drilling Fluids details the formulation and application of these systems.

The following field practices are used to minimize problems from unstable formations.

• Density control – Maintain the proper density. If in mountainous areas, more mud weight may be needed than indicated by gas pore pressures. Surges and swabs must be avoided in formations susceptible to falling in. Keeping the wellbore full of fluid on trips is also good practice for wellbore stability as well as blowout protection.

• Rheology – Adequate hole cleaning is needed to remove any formation pieces falling into the hole and to differentiate between unstable formations and a hole cleaning problem. Turbulence may wash out unconsolidated and weak formations. Turbulence may also aggravate a formation in which hydratable shales have started falling into the wellbore.

• Fluid loss – The API fluid loss by itself is not an indication of relative formation protection. The level of fluid loss control must be based on field experience for each individual drilling area. 

• Hole deviation – In high angle wellbores, fractured formations with deviation problems, and mountainous areas, extra care must be taken to protect against unstable formations.

MAIN PROPERTIES OF DRILLING FLUIDS
Mud engineers use standardized tests to determine if the mud is functioning properly. These test procedures are administered by the American Petroleum Institute’s Drilling Fluids Standardization Committee. 

This section discusses the following common properties and how these properties relate to the proper functioning of a mud:

• Density 
• Rheological properties
• Filter cake quality 
• Inhibition 

This section also briefly discusses tests used to determine mud properties. Complete descriptions are given in Module LAB203.02.

Density 

Density is the weight of a given volume of fluid. It can have units of:

• Pounds per cubic foot, lb/ft3 
• Pounds per gallon, lb/gal 
• Kilograms per cubic meter, kg/m3 
• Grams per cubic centimeter, g/cm3 

Figure 12 shows the range of mud weights that can be obtained using various formulations of drilling fluids.

FIGURE 12. Mud Classification by Density

Rheological Properties

Rheology is the study of the viscosity characteristics of a mud. Viscosity is a measure of thickness or thinness. On a drilling rig, the viscosity is measured in several different ways, including:

• Funnel viscosity – Used for quick and easy indications of viscosity changes 
• Plastic viscosity – Related to the solids content of the mud 
• Yield point – Related to the chemical forces acting on the mud 
• Gel strengths – Related to suspension and time-based thickening tendencies Rig personnel can measure the funnel viscosity of the mud, but the other viscosity properties must be taken by the drilling or mud engineer using a viscometer. 

A complete discussion of Rheology is given in Module LAB203.05.

Filter Cake Quality

Quality control of mud fluid loss is directly related to filter cake quality. The factors that affect cake quality are:

• Particle size distribution 
• Long-chain polymers 
• Compressibility 
• State of flocculation of the mud

To get a filter cake with low permeability, a particle size distribution from submicron to multimicron is needed. Of all the particles in a mud, the flat, platelike bentonitic particles form the most smooth, even, and least permeable bridging material. Drilled solids normally change this distribution to larger, more permeable cakes. Commercial bentonite and longchain polymers help in making a tougher and thinner cake.

Filter cakes from drilling fluids have a wide range of compressibilities. The amount of compression is determined by the nature and size of the solid particles in the cake. Filter cakes that are highly compressible will be compacted as the differential pressure goes up. This gives a lower permeability and reduced filtrate volume into the formation. Incompressible cakes will not compact, and the filtrate into the formation will increase in direct proportion to the differential pressure.

Bentonite forms the most compressible cake, compared to cakes with drilled solids and barite. Therefore, in addition to the total solids content of the mud, the solids content of the mud should be analyzed for high and low gravity solids and bentonite content. The barite content is set by the mud weight being using. Adequate bentonite content should be maintained and the drilled solids content should be minimized to obtain a compressible filter cake (Figure 13)

FIGURE 13. Pressure Test for Filter Cake Compressibility

The compressibility of the cake can be measured in the field. Simply use a HTHP filter press at two pressures, the higher twice the pressure of the lower. A slight increase, or lowering of the filtrate at the higher pressure, indicates a compressible cake.

Flocculated solids in a mud result in thick, weak filter cakes. Flocculation is caused by salts, salt waters, cement contamination, and other contaminants. In addition, higher temperatures cause clays to flocculate. Polymeric dispersants are used to deflocculate the mud system. The submicron sizes created by many of these chemical thinners give low API fluid loss values. A build-up of these particles, however, tends to reduce drilling rates.

Inhibition

The inhibitive property of a drilling fluid relates to the level of interaction between the mud and a water sensitive formation. The level of inhibition should be matched to the formation. Research and field experience show that the most inhibitive muds are provided by:

• Oil-based fluids 
• Cations, such as potassium, ammonium, and calcium 
• Long-chain, film-forming polymers 

These mud systems are discussed in detail in the Drilling Fluids Course Modules LAB203.05 and LAB203.03 for oil-based mud and water-based mud, respectively. Inhibition is not a property that can be easily tested. Swelling or rolling tests adapted from the laboratory have been used in the field. They are only tests for the relative shale stabilizing influence of the mud being used. When on the rig, however, the following conditions indicate possible shale instability problems. If instability is expected, then the mud system can be made more inhibitive. 

• Shale shaker – Watch the shale shaker often to determine the normal coverage of the screen for the hole size and current drilling rate. Any increased volumes of formation over the shaker should be examined. Know the size of the cuttings in relation to the bit. Any larger pieces over the shaker are an indication of shale instability.
• Connections/trips – Watch for excess torque and drag and fill on bottom. 
• Solids build-up – When using a highly dispersed mud system, some shale problems (highly mud-making shales, for example) are masked by the shale disintegrating into the mud. 

Test Procedures

Complete descriptions of each of the tests are given in the API Recommended Practices (RP13B-1 for water-based mud and RP13B-2 for oil-based mud), which are attached to Module LAB203.02 on Drilling Fluid Testing. 

A mud engineer on the rig usually runs the appropriate API tests to determine the mud properties. A drilling engineer must evaluate those tests and make judgments based on the mud data presented. In addition, the following factors must be taken into account:

• Hole conditions 
• Formation being drilled 
• Bottomhole temperatures and pressures 
• Solids control equipment 
• Drilling rate 
• Location – onshore or offshore 
• Overall economics

COMPONENTS OF DRILLING FLUIDS
Muds are composed of a base fluid and additives. The additives perform certain functions or adjust one or more of the mud’s properties. This section will discuss the following base fluids: 

• Air 
• Water 
• Oil 

This section will also discuss the following types of additives: 

• Weight control additives
• Viscosifiers and thinners 
• Fluid loss and filter cake controllers 
• Bentonite extenders, flocculating agents, chemical precipitators, and temperature stabilizers

Air

Air is a base fluid used to lower the hydrostatic head to drill depleted and under-pressured formations. Air is also used in geothermal drilling because of the high temperatures encountered as well as low pressures and lost circulation. In addition, very fast drilling rates can be maintained with ultra-low densities. High volume compressors are needed to maintain the volumetric flow required to clean the hole. This volumetric flow rate may result in high fluid temperatures and has resulted in downhole explosions. 

If water is encountered in formations being drilled with air, the fluid must be converted to mist by adding surfactants. Water flows are best handled by converting the fluid to a foam with foaming agents and a stabilizer. Foam stabilizers are usually drilling fluid polymers such as xanthan gum or hydroxyethyl cellulose (HEC). 

Water

By far, most of the muds in the world use water as the base fluid. Usually it is fresh water, but salt waters are often used for supply or economic reasons. A chloride content of about 5000 ppm is the upper limit for a mud to be considered a fresh water mud. The hydration of bentonite is inhibited above that chloride level.

The properties of water can be modified by dissolved chemicals:

• Salt – Sometimes the available supply of water for making a drilling fluid is not fresh water. In offshore drilling, for example, you may have to use sea water. At other times you may want to add dissolved salts, such as sodium chloride (NaCl), potassium chloride (KCl), or calcium chloride (CaCl). In addition to these chloride salts, drilling carbonates or sulfates (gypsum) can add soluble ions to the water phase. In some cases, these soluble materials cause mud instability and are considered as contaminants. 

• Alkali – The pH of the mud systems are usually run in the alkaline range by the addition of alkali materials. Caustic soda (sodium hydroxide or NaOH) is most commonly used. Caustic potash (potassium hydroxide or KOH) is used in inhibitive muds. Lime or calcium hydroxide [Ca(OH)2 ] is used in lime-based muds and in oil-based muds. 

• Polymers – Large water soluble polymers are used to change the properties of water and suspended solids. They can be used to derive the essential properties of viscosity, viscosity reduction, and fluid loss. 

• Surfactants – Surfactants change the wettability of water and solids through adsorption. They are used to prevent foaming or to emulsify oil. Other surfactants will adsorb onto steel and act as lubricants. 

Oil

Oil is used as the continuous phase in oil-based drilling fluids. Consideration of safety, low viscosity, and availability has made diesel oil the most common oil. Where environmental concerns are higher, special oils have been prepared through the removal of aromatic fractions.Table 1 summarizes the advantages and disadvantages of these base oils.

TABLE 1. Oils Used for Oil-based Muds

Oil soluble components are mainly used to stabilize the emulsification of water into the oil. The emulsified water adds to the viscous properties of the mud and the fluid loss control properties. These are fully described in Module LAB203.05.

High Density Solids

Table 2 shows the materials that are used to weight-up muds.

TABLE 2. High Density Solids to Weight-up Muds

The most common weight material is barite. It has a relatively high density, is not abrasive, and is readily available. In oil muds, the weight material of choice is usually an iron oxide material such as hematite. The weighting material is present in high concentrations, has a significant influence on the properties of the muds, and is a major cost element. The main problem faced in solids control, discussed in Module LAB203.06, is the separation of the weight-up solids from the low gravity drilled solids.

Clay Solids for Viscosity

The primary viscosifier for water-based muds is sodium bentonite. API Specification 13A sets specifications for bentonite quality. The specifications make certain that mud companies supply high yielding clays that are mostly sodium montmorillonite. The API recommends the following properties from bentonite for drilling fluids(Viscosity reading, yield point, and filtrate are measured on a suspension of 22.5 g bentonite in 350 cm3 of distilled water.Filtrate measurement and viscometer readings are taken at a temperature of 75 °F ± 5 (24 °C ± 3):

• Viscosity – 600 rpm dial reading: 30 minimum
                    Plastic viscosity/yield point ratio: 3 maximum

• Fluid loss – 15.0 cm3 maximum

A derivative of bentonite can be used in oil-based muds for viscosity control when reacted with cationic surfactants so that it disperses in oil.

ELEMENTS OF A DRILLING FLUIDS PROGRAM

An adequate and realistic drilling fluid program must be developed for each well drilled. Although the mud cost is usually only 6 to 8% of the total well cost, the mud used may have a big impact on drilling a troublesome well. Mud programs must be developed for both exploratory (wildcat) wells and in-field development drilling. For wildcats, it is necessary to spend more for the mud and put various safeguards in the program. For field wells, the mud properties required are usually more predictable and costs can be controlled better.

The elements of a successful mud program include:

• The formations to be drilled 
• The formation pressures to be encountered 
• Identification of previous problems 
• The casing program 
• A mud selected for each interval drilled 
• The designation of the program supervision 
• Critical review of performance after the hole is drilled The design of a drilling fluids program will be discussed in Module LAB203.09 and brings together the topics discussed in the course. The key features of the drilling fluids must be matched to the requirements to drill the well.

GLOSSARY

barite

Natural barium sulfate used for increasing the density of drilling fluids. If required, it is usually upgraded to a specific gravity of 4.20.

cuttings 

Small pieces of formation that are the result of the chipping and/or crushing action of the bit. 

equivalent circulating densit

For a circulating fluid, the equivalent circulating density in lb/gal equals the hydrostatic head (psi) plus the total annular pressure drop (psi) divided by the depth (ft) and by 0.052. 

gel strength 

The ability or the measure of the ability of a colloid to form gels. Gel strength is a pressure unit usually reported in lb/100 ft2. It is a measure of the same inter-particle forces of a fluid as determined by the yield point, except that gel strength is measured under static conditions and yield point under dynamic conditions. The common gel strength measurements are the initial gel and the 10-minute gel. 

hydrostatic head 

The pressure exerted by a column of fluid, usually expressed in psi. To determine the hydrostatic head, multiply the depth in feet by the density in pounds per gallon by 0.052. 

inhibited mud 

A drilling fluid having an aqueous phase with a chemical composition that tends to retard and even prevent appreciable swelling or dispersion of formation clays and shales through chemical and/or physical means. 

oil-based mud 

The term is applied to a special type of drilling fluid where oil is the continuous phase and water the dispersed phase. Oil-based mud contains blown asphalt and usually 1 to 5% water emulsified into the system with caustic soda or quick lime and an organic acid. 

polymer 

A substance formed by the union of two or more molecules of the same kind linked end to end into another compound. These molecules have the same elements in the same proportion, but a higher molecular weight and different physical properties, for example, CMC and starch.