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Drilling Fluids
نویسنده : رضا سپهوند - ساعت ۱۱:٤٢ ‎ق.ظ روز ۱۳٩٤/٥/٦
 

 Drilling Fluids


Attempt any FIVE questions

1.    Describe the following
(a)    Plastic viscosity
(b)    Yield point and
(c)    Gel strength
                     (20 Marks)

2.    Explain the following drilling fluid materials.

(a)    Barium sulfate
(b)    Bentonite
                     (20 Marks)
3.    Explain with the sketch for mud balance and marsh funnel.             (20 Marks)
    
4.    Describe the classification of drilling mud.                             (20 Marks)

5.    Explain Mechanical emulsion.                                 (20 Marks)

6.    Describe chemical emulsion.                                     (20 Marks)




















1.(a)  Plastic Viscosity
    Mud is composed of solids that contribute to apparent viscosity. By definition, plastic viscosity is the shearing stress in excess of yield point that will induce a unit rate of shear. Plastic viscosity is that part of flow resistance caused by mechanical friction. This friction occurs (1) between the solids in the mud. (2) between the solids and the liquid that surrounds tem, and (3) with the searing of the liquid itself. For practical field purposes, however, plastic viscosity depends upon the concentration. Size, and shape of mud solids.
    In muds containing high solids b volume, the friction beween te particles is increased. Under this condition; plastic viscosity is increased with an accompanying increase in apparent viscosity. Decreasing the size of the solids at constant volume also increases the plastic viscosity. There is a net effect of increasing surface area, and

1.    Dilution – In most cases, water is added to dilute the solids concentration which in turn lowers the apparent viscosity and plastic viscosity b decreasing friction between the particles.
2.    Shaker Screen – Running the mud over the shaker screen removes the larger particle size solids, reducing solids concentration. Running water on the shaker screen washes fine cuttings into the mud and should be avoided.
3.    Centrifuge or Cyclone Separator – these machines mechanically separates solids by their size and mass. This in turn reduces the total solids concentration:
4.    De-sander – This machine mechanically removes the sand from the mud, which reduces the solids concentration.

1.(b)  Yield Point (lb/100 sq.ft)
    Yield point, the second component of resistance to flow in a drilling fluid, is a measurement of the electro-chemical or attractive forces in mud. These forces are a result of negative and positive charges located on or near the particle surfaces. Yield point is a measure of these forces under flow conditions and is dependent upon; the surface properties of the mud solids. (2) volume concentration of the solids, and (3) the electrical environment of these solids (concentration and types of ions in the fluid phase of the mud). High viscosity, reslting from high yield point or attractive forces is caused b;
1.    Introduction of soluble contaminants such as salt, cement, anhydrite. Or gyp, which necturalize the negative charges of the clay particle. Flood and increased yield point result
2.    Breaking of the clay particles b the grinding action of bit and drill pipe, creates new residual forces (broken bond valances) on the broken edges of the particle. These forces tend to pull the paticles together in disorganize form of flocs.
3.    Introduction of inert solids into the system increases the yield point this results in the particles being moved closer together. Because the distance between each particle is now decreased, the  attraction between particles is increased.
4.    Drilled Hydratable  shales or clay introduce new active solids into the system increasing attractive forces by brining the particles closer together, and by increasing the total number of charges.
5.    Insufficient or over treatment with chemicals increases the attractive forces

  Yield point is that part of  resistance to flow which  may be controlled by proper chemical treatment. As the attractive forces are reduced by chemical treatment. The yield point will decrease. Reduction of yield point will also decrease the apparent .
        Yield point is a measurement of the attractive forces in a mud system or it might be said to be a measure of effectiveness of chemical treatment under flow conditions. Equally important are the attractive forces causing gel strength.

1.(c)  Gel Strength (1 b / 100 sq.ft)
                           Gel strength measurements denote the thixotropic properties of the mud. They are a measure of the attractive forces under static or-non-flow conditions. Yield point on the other hand is a measurement of attractive forces under flowing conditions and should not be confused with gel strength. However, since both gel strength and yield point are a measure of the force of flocculatin as yield point decreases the gel strength will usually decrease. A low yield point does not necessarily indicate a condition of 0/0 gels. Additional, but without any appreciable reduction in apparent viscosity.
                  Gel strengths are usually classified as progressive (strong) or as fragile (weak) type gels (Figure 2-8). A progressive gel may be described as one that may start low initially, but consistently increases with time. This type gel strength as strong or firm, and hard to break. The progressive gel often occurs because of a high concentration of mud solids. Progressive gels are undesirable because they may create problems.


2.(a)  Barium Sulfate
                    In the past, a variety of materials have been used as weighting agents for mi such as barite, strontium sulfate, iron oxide, amorphous silica, calcium carbonate, a native clays. The use of barite as a weighting agent for drilling mud was lo, barite for use in mud prior to 1943 prompted the se of less effective material as weighting agents has dwindled rapidly, and barite, because of its low cost hig specific gravity, cleanliness, inertness, and freedom from impurities, has become the standard mud-weighting material.
                      Barite, which is naturally occurring barium sulfate, is also commonly known as “barites”, “heavy spar”,and locally in Missouri as “tiff”. Its chemical formula is BaSO4 , and pure barite contains 65.7% BaO and 34.3%SO3.Commecial forms of barite may run a low s 92% BaSO4. with  impurities consisting of silica, iron oxide limestone, dolomite, shale, etc. Barite is insoluble in water, has a hardness of 2.5 to 3.5 on the Mohs scale, has a specifc gravity of 4.3 to 4.4 , and the color is white to light shade of grey, red, and brown. The mineral has a white streak, a pearly to vitreous luster, and commonly occurs s crystals of the orthorhombic, dipyrsmidai class.
                         Geologically, barite is thought to have its origin as a deposition from hot waters circulated from deep in the earth, and it is found to occur in four principal types of deposits:
1.    In limestone and  other sedimentary rocks , as veins and lenses,        cavity fillings , or replacement deposits.
2.    As residual nodules in clays, derived from weathering of barium- bearing rocks such as dolomite or limestone.
3.    In beds or masses , as replacements in limestones , shales , and other  sedimentary rocks.
4.    As a gangue material in metalliferous veins or beds

The occurrence of barite is widespread and has been reported on all continents and in all major countries of the world. The deposits vary in size from those containing several million tons down to very small deposits containing only a few roc fragments, and it seems to be characteristic of barite to occur in deposits containing relatively small tonnage. The purity of barite as it occurs in nature varies considerably, from veins of almost pure barium sulfate as a gangue mineral. Barite is such a relatively low-priced commodity that commercial production can be considered only from those places from which it can be delivered at a low cot of the principal markets. The choice of a deposit to be mined is often not a question of its geology buy rather of its geography, because of the relatively high cost of transportation. Barite occurs in some deposits in a sufficiently pure state to be commercially acceptable as removed, where as in other deposits the must be beneficiated by various methods, such as washing, jigging, tabling, flotation, etc.

2.(b)  Bentonite
Bentonite deposits occur in beds from a few inches to several feet thick, mainly in the Tertiary of the Cenozoic era, upper Cretaceous, and Mesozoic, but to some extent in the Paleozoic rocks in many parts of the United States and Canada and depoists have been reported from Mexico, China, France, Germany, Poland, Russia, Japan, Italy, South Africa, and various other places.
These deposits may well have been formed during expulsion from a volcano and subsequent distribution b air currents in contact with corrosive gases that attacked the surface of the particles and rendered them open to relatively rapid disintegration when the ash fell in moist climates or into shallow bodies of water. Such conditions may have existed in Cretaceous and Tertiary times in the districts whee bentonite now occurs. The action of waer first caused the ash to disintegrate into hydrous silica and alumina with colloidal propertics and the base to dissolve. Part of the soluble salts was adsorbed, and the rest leached out. This state was supposed to have been followed b the incipient growth of crystals from a large number of nuclei with the formation of the metacolloidal condition. Bentonite, then is supposed to consist of colloidal matter, minute crystalline matter, and included impurities.
Although most bentonites are believed to have been formed from volcanic ash, Ross and Shannon point out that some deposits have been formed in situ by the devitrification not only of glassy igneous ash or tuff but ocasionall, of lava flows and even of hypabyssal intrusives.
Bentonite outcrops are unique and striking. As little vegetation will grow on them, they are barren, and because o the peculiar physical properties of bentonie these weathered outcrops often present a crinkled, orallike appearance. The later effect has been studied b Twenhofel who concludes that the surface cracks a.e caused by the lag in absorption of water by bentonite. The internal portion of bentonite is dry buy finally absorbs water and swells greatly, producing cracks in the surface layer, which has mean-while become more or less dry. After a rain many bentonite outcrops are covered with a thick mass of slippery jelly, but in dry weather the surface many be dry and fluffy or may have a peculiar granular appearance.
Bentonite is one of the most useful mud materials, contributing viscosity, suspending and sealing properties to the fluid. A ton of drilling mud grade bentonite makes approximately 100 barrels of mud having a viscosity of 15 centiposises.
Bentonite is used throughout the world in drilling mud, but there is no source of information as to the amount used. On the basis of a unit consumption comparable to the U.S, it might be estimated that in 1961 an amount approximating 150,000 tons of bentonite was used in drilling mud. Outside of the U.S. Some Wyoming bentonite is exported for drilling operations out side the U.S, but most of the supply comes from other sources.
Much of the bentonite that occurs outside of Wyoming is a calcium bentonite which has properties that are quite different than sodium bentonite used in mud. During recent years improvements have been made in methods and processes for base exchanging certain selected calcium bentonite is quite equivalent to Wyoming bentonite for drilling mud use; however, a considerable proportion of the bentonite presently being used in foreign operations does not meet the desired standards.


3.(a)  Magcobar Mud Balance
    
The Magcobar mud balance (Figure 4.1 ) consists principally of a base on which rests a graduated arm with cup, lid , knife edge, level vial, rider and counterweight. The constant volume cup is affixed to one end of the graduated arm. Which has a counter weight at the other end. The cup and arm oscillate in a plane perpendicular to the horizontal knife edge, which rests on the support, and are balanced by moving the rider along the arm.

            

Magcobar Mud Balance


3.(b)  Marsh Funnel

The Marsh funnel ( Figure 4.2 ) is inches in diameter at the top and 12 inches long. At the bottom, a smooth-bore tube 2 inches long, having an inside diameter of 3/16 inch is attached in such a way that there is no constriction at the joint. A wire screen, having 1/16 inch openings, covering one-half of the funnel is fixed at a level of ¾ inches below the top of the funnel


 

Marsh Funnel and One Liter Cup

4.  Classification of Drilling Muds
Classification of drilling muds by generic name results in two mud systems i .e , water-base types as the letter are primarily restricted to special purpose drilling. Water-base muds consist of a large number of separate systems since the only requisite is the use of water for the base vehicle. The first split in classifying water-base muds is based upon te salinity o the aqueous phase. Bentonite will dissolve salts up to certain percentages, but above tese its properties are adversely effected. Water-base fluids in which bentonite performs satisfactory are known as non-saline and those in which it does not as saline. The definition of a saline fluid for purposes of this discussion is an aqueous fluid containing sufficient soluble salt of an kind to prevent bentonite from functioning  satisfactorily as aviscosity and fluid loss controlling agent.
    Of all these systems the fresh water type is the basic, most universally used md system. This is te natural result of the availability and normally satisfactory functioning of water as the fluid vehicie. The remaining mud systems have been developed to overcome drilling conditions which fresh water muds have difficult handling or for which they are totally unfitted. These substitute systems are specrally compounded and usually are more costly to build and maintant than the fresh water type. Their use, however, for the situation for which they are fitted is often the difference between completing or abandoning a hole and without them deep drilling in many areas would be seriously handicapped.
    With this discussion in mind, the drilling fluids in use today are classified by major types and components in Table 5.1. Since the revision of this book in 1953 muds have become increasingly specialized, making it difficult to catalog the various systems under a single set of principles however. Table 5.1 rebresents one such method.
    Additional methods of classitication are used to further differentiate mud systems such as time-starch. Time-starch-emulsions, salt water-starch. Gyp-Q-Broxin, stabilized. Low surface tension, calcium-surfactant, petronat. E.P etc. These are attempts to more closely restrict the mud composition or properties to local terminology or for greater exactness.

1.    Natural Muds – No Treatment
2.    Fresh Water Muds (sodium chloride less than 1%; calcium ions less than 120 ppm)
a.    Low pH-Phosphate (pH to 8.5)
b.    Caustic-Quebraho (pH .6 to 10.5)
c.    High pH (pH 12.0 to 13.0)
d.    Chrome Lignosulfonate  (pH 8.5-10.0)
3.    Saline (monovalent) Muds (sodium chloride 1.0% or grester)
a.    Brackish Water
b.    Sea water (approximately 3.5%NaCL )
c.    Saturated Salt  Water
    4.    Calcium (Polyvalent) Muds
        a.    Low Lime
        b.    High Lime
        c.    Gypsum
        d.    Calcium chloride, acetate, or other polyvalent cations.
    5.     Low Solids Muds (solids less than 7% by volume)
    6.    Oil Emulsions, Oil to 15% in Water
    7.    Invert Emulsions, Water (20 to 70%) in Oil
    8.    Oil  Base
    9.    Sodium Silicate (Obsolete)


5.  Mechanical Emulsions
    An emulsion may be formed by the addition of either crude oil or diesel oil to a good water base mud. The ordinary water base muds contain one or several emulsifying agents. The constituents of the mud are materials such as clays, finel, divided shales, fluid loss control agents, and certin thinning ahents, all of which promote emulsification of the oil. Emulsifying materials forming mechanical type emulsions may be placed into three general groups.
1.    Powdered Solids- Clays, Bentonites, and finely divided shales all of which can be adsorbed at the interface of the oil globule. Figure 5.2 demonstrates how these materials form a protective film around the oil droplet. Bentonite (Magcogel) is one of the best of the solids emulsifiers.
2.    Organic Colloids – Fluid loss control agents (such as starch, gums,and CMC) form insoluble films around the oil globule, acting much like the powdered solids.
3.    Lignin compounds – Dispersants, such as lignite, greatly improve the emulsion. These compounds perform as emulsifying agents by improving the dispersion of the oil droplets.

When oil is stirred into drilling mud containing little or no chemical treatmerk a mechanical emulsion is formed. Figure 5.3 is a photomicrograph of a mechanical emulsion formed by stirring oil into a 5% bentonite suspension. Although the individual particles are not visible, there are opaque areas around each globule where the solids are concentrated. Such emulsions are less stable than chemical emulsions.
A more stable mechanical emulsion is obtained when chemical dispersants such as TannAthin or XP-20 are added; acting in the manner previousl discussed. The chemical necessary to emulsify the oil will vary with te amount of oil added. Generally, 2 to 3 lb/bbl of chemical is adequare, but at times more may be required.
These mechanical emulsions may be entirely adequate. They are economical, easy to prepare and easy to use. Materials in an ordinary mud may be all that needed to produce a stisfatory emulsion. The emulsion will “slick up” the hole decrease fluid loss, increase bit life, increase rate of penetration, decrease total rotating hours, and hence, educe drilling costs.
Mechanical emulsions, wile stable under normal conditions, may not remain so when the mud becomes flocculated. Figure 5.5 shows the effect of flocculation on a mechanical emulsion prepared with 10% crude oil in a slurry containing 20 lb/bbl of bentonite. The emulsion in this sample was broken when 10,000ppm salt was added to the slurry. The bentonite particles surrounding the oil globules become flocculated allowing the oil to break out.
    The mechanical emulsifiers have little effect on surface tension because they are not water soluble. Mechanical emulsions sow no tendency to oil wet. The colloidal solids emulsifiers remove oil from metal surface and prevent oil wetting. Chemical emulsions, however, are capable of decreasing surface tension and promoting oil wetting.
    An emulsion may be made more stable b forming a chemical emulsion. Certain chemical emulsifiers are available to emulsify the oil in the mud. Those currently being used are placed in three groups.

1.    Anionic active agents – This group includes the lignosulfonate (Spersene and Kembreak) and the petroleum sulfonates (Magconate)
2.    Non-ionic surface active agents – DME (Drilling Mud Emulsifier)
3.    Mixed formulated blends – Magco Mul, Salinex

Group 1, the anionic active agents, include compounds such as the lignosulfonates, these are weak chemical emulsifiers and may satisfactorily emulsify the oil. They improve the mechanical emulsifying potential of the clas by dispersion and also add a slight reducation in surface tension. They produce a weak polarization of the molecule, thus improving the stability of the emulsion. Magconate, the other example in Group 1, reduces surface tension considerably. The material has a mixed polar-non-polar type of molecular structure. Magconate uses two of the best means for making emulsions. First, the surface tension is reduced and small droplet are easily formed. Second, the non-polar potion of the non-ionized oil and the polar portion is attracted to the ionized water. This arrangement of the molecules forms a very tough film or skin around the oil globules at the interface of the oil and water.

Group 2, the non- ionic emulsifiers, are best described in terms of the linkage between the hydrophobic (water repelling) and the hydrophilic (water solubilizing) portion of the molecule. Tese linkages include; ether linkage, ester linkage, amide linkage, miscellaneous linkage and multiple linkage. For a given hydrophobe, water solubility increases as the hydrophilic chain is lengthened in proportion to the size of the hydrophobic part of the molecule. Because it is possible to shorten or lengthen either the hydrophobic or ydrophilic part of the molecule, emulsifying agents can be tailor-made for specific applications.
DME is an excellent non-ionic emulsifier. The material has the fight balance between the hydrophobe and hydrophile to maintain a tight oil-in-water emulsion. Because of its solubility in both oil and water, DME reacts to form an emulsion in much the same manner as do the anionic emulsifying agents. It stabilizes the emulsion by arranging the molecules at the oil-water interface. The oil soluble portion pointing toward the oil, and the water soluble portion toward the water. These compounds also act as surface tension reducers, and are also powerful surface acting agents. Because they are surface active agents, their application is limited to flocculated muds and low solids muds. The material is not used in well dispersed mud systems.
Group 3, is the mixed blends. Magco Mul and Salinex are two materials in this classification. Magco Mul is applied in fresh water systems that are relatively free of calcium and/or magnesium salts. From 3 to 4 lb/bbl of Magco Mul is recommended for muds containing approximately 10%oil. Salinex is an emulsifier especially designed to prepare oil-in-waer emulsions in seawater and salty muds. It is an effective emulsifier in muds having salt contents from 15,000 p-pm salt to near saturation.