A gel consists of polymers linked through covalent and/or non-covalent
interactions, to create a three-dimensional network. In whole egg as well as in
white and yolk, proteins are responsible for the gelling properties. Gelation
occurs when the protein stability in solution is modified, i.e., when the
equilibrium between attractive (Van der Waals) and repulsive (electrostatic,
steric) interactions is disrupted. The electrostatic repulsions vary with the net
charge of the proteins, that means with the ionisable protein groups and with the
physico-chemical characteristics of the solvent (pH, ionic strength). The
treatments that decrease the repulsive interactions, such as adjustment of pH
at proteins pI or addition of salts, induce destabilisation and thus can result in the
formation of aggregates or gels.
Moreover, some treatments can modify the protein structure, with
consequences for the repulsive and attractive interactions mentioned above.
This is especially the case during heat treatments, which are the major techno-
logical treatments used in the food industry for egg white and yolk gelation.
Heat-induced gelation of egg conforms completely with the model of heat
gelation of globular proteins. It is a two-step phenomenon: in the first stage,
unfolding of native proteins occurs, disrupting the well-defined secondary and
tertiary structures and producing denatured proteins exposing their inner
hydrophobic regions; following unfolding, the denatured proteins interact to
form high molecular weight aggregates that can further interact with each other
to result in a three-dimensional gel . The unfolding and
aggregation steps depend on many factors (protein concentration, ionic strength,
pH, presence of sucrose, etc.) that can modify the number and/or the kind of
interactions, with final consequences on the gel rheology. In the heat-induced
gels of egg proteins, the interactions involved are predominantly hydrophobic
and electrostatic, but some highly energetic interactions can be observed
(disulfide bridges); thiol and amine groups are indeed very reactive, especially
in alkaline conditions.
Monday, June 28, 2010
Wednesday, June 23, 2010
Industries using guar gum
Guar gum is a white to creamy coloured, free flowing powder and free from extraneous matter. Its ability to suspend solids, bind water by hydrogen bonding, control the viscosity of aqueous solutions and form strong tough films, have accounted for its rapid growth and use in various industries. Industrial grade Guar Gum is used in Paper, Textile Processing, Explosives, Detergents, Drilling Fluids, Ceramics, Paints and many other industries. The purified grade is used in the Pharmaceuticals, Dialectic, Cosmetic and Food Industries. Guar gum is a natural product, and because it has the ability to swell by hydrolyzing with water, it can be used in a variety of water systems for food and industrial applications. Guar gum can viscosify, stabilize, and emulsify water systems as well as bind moisture to itself.
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Guar Gum for Food, Pharmaceutical & Dialectic Industries:
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Guar Gum for Bakery Industry:
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Guar Gum for Grass Growing / Erosion Control :
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Guar Gum for Cosmetics:
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Guar Gum for Fish Farming :
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Guar Gum for Oil Well Drilling :
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Guar Gum for Explosives (as Water Blocking Agent in Nitro-glycerine, Slurry Explosives, Ammonium Nitrate & Dynamite Explosives):
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Guar Gum for Paper Industry:
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Guar Gum is also used in the following industries:
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Sunday, June 20, 2010
La gomme de Guar E412
La gomme de Guar E412
Origine et fabrication
guar gum beansLe Guar fait partie de la famille des gommes issues des graines. Cette gomme est donc extraite d’une famille de légumineuses (Cyamopsis tetragonolobus) dont le fruit est une gousse et qui est cultivé en Inde et au Pakistan. Elle constitue les polyssacharides de réserves des légumineuses que l’on appelle les galactomannanes. Il existe 2 types de procédés pour extraire la gomme de Guar des graines :
guar gum powder
guar gum powderUn procédé mécanique
Tout d’abord, les coques des gousses sont éliminées puis un broyage modéré des graines est effectué pour dégager l’endosperme de la graine qui contient la gomme jusqu’à l’obtention d’une poudre. La poudre obtenue est opaque.
Un procédé chimique
Les graines sont solubilisées à chaud puis la solution est filtrée sur silice. Ensuite, le filtrat recueilli est précipité avec de l’alcool isopropylique. Le coagulum obtenu est alors lavé, pressé et broyé.
Structure
guar gum chemicalLe Guar est un galactomannane constitué d'une chaîne de β-D mannose sur laquelle sont branchées des unités α-D galactose. Il y a 1 galactose pour 2 mannoses.
Propriétés de la gomme de Guar
Solubilité
De part sa structure très ramifiée, le Guar est soluble à froid. En effet, la présence d’une quantité importante de galactoses ramifiés facilite la pénétration de l'eau à l’intérieur du grain et l'écartement des chaînes de mannose.
Epaississantes
La gomme de Guar, de part sa forte viscosité à température ambiante (1000 à 6000 mPa.s), est un épaississant puissant. De plus, sa viscosité reste inchangée lorsqu’on applique de forts cisaillements.
Synergie avec les autres gommes
La gome de Guar présente des synergies par association intermoléculaire avec des polysaccharides linéaires : Xanthane, Kappa – Carraghénane.
Dans les applications alimentaires, le guar est rarement utilisé seul, il est souvent associé à d’autres hydrocolloïdes.
Applications alimentaires
| Domaine | Propriétés du Guar | En association avec |
| Préparations ménagères | Soluble et visqueux à froid | Caroube, carraghénanes et xanthane |
| Boissons | Augmente la viscosité, donne du corps | |
| Produits Laitiers | Augmente la viscosité, donne du corps | Caroube et carraghénanes |
| Panification | Renforce réseau gluten | Caroube et xanthane |
| Sauces | Epaississant | Xanthane et amidon |
La gomme de guar est employée à une concentration inférieure à 1% comme épaississant.
Pour faciliter sa dispersion, il est aussi préférable de mélanger la gomme de guar avec du sucre ou avec un autre ingrédient facile à disperser et plus abondant (farines, amidons).
Cette gomme constitue le produit le plus courant pour apporter de la viscosité à toutes sortes de recettes car elle est sans interactions avec les autres additifs.guar gum
source: cuisine-et-molecule.fr
Tuesday, June 15, 2010
guar gum
Guar Gum History
Guar is a native to the Indian subcontinent. Guar is grown mainly in India, Pakistan, United States and also in some part of Africa and Australia.
In old times, Guar was only used as rich protein to feed cattle. It is also used as green vegetable in India. After Second World War there was major shortage of locust bean gum which adversely affected the textile and paper industries. At that time Guar Gum was found as the most suitable substitute for scarce locust bean gum. In 1953 the extraction technology of guar gum was commercialized in USA and India after decade of period.
Guar Plant
The guar plant is an annual plant known as 'Cyamopsis Tetragonaloba'. The important source of nutrition to human and animals is the legume, it regenerates soil nitrogen and the endosperm of guar seed is an important hydrocolloid widely used across a broad spectrum of industries.
The guar plant flourishes in extremely drought resistant and semiarid regions where most plants perish. It grows best in sandy soils. The ideal areas for farming are West, Northwest India and parts of Pakistan. The major processing centers of Guar Gum are in the North Western states in India.
The guar plant grows from 2 feet to 9 feet high. The plant’s flower buds start out white and change to a light pink as the flower opens. The flowers turn deep purple and are followed by fleshy seed pods which ripen and harvested in summer.
The seed pods grow in clusters giving guar the common name cluster-bean. A gum extracted from the guar beans forms a gel in water, commonly referred to as guar gum. Guar is extremely drought resistant and thrives in semi-arid regions where few plants thrive. When limited moisture is available the plant will stop growing but does not die. Guar gum is also known as guarkernmehl, guaran, goma guar, gomme guar and galactomannan.
Guar Harvesting period
A growing season of guar is 14 to 16 weeks and requires reasonably warm weather and moderate flashing rainfall with plenty of sunshine. Too much rain can cause the plant to become more 'leafy' resulting thereby reducing the number of pods or the number of seeds per pod which affects the size and yield of seeds. The crop is generally sown after the monsoon rainfall in the second half of July to early August and is harvested in late October early November. The Guar is a naturally rain fed crop. Depending on the monsoon rainfall the total size of Guar crop varies from year to year. After harvesting, when the pods become dry through sunlight, they are beaten off and during this process, the seeds come out of the pods.
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Guar Extraction Methodology
Contagion of the natural gums available at present occurs mostly due to poor handling. There are various tools and system available through which natural gums can be extract completely hygienic from the tree.
Guar Scientific classification
Kingdom: Plantae
Division: Magnoliophyta
Class: Magnoliopsida
Order: Fabales
Family: Leguminosae
Tribe: Indigofereae
Genus: Cyamopsis
Species: C. tetragonoloba
Botanical name: Cyamopsis tetragonolobus (L.)
Synonyms: Cyamopsis psoralioides L.
Part Used: Seeds
Vernacular Name: Guar
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Guar Standard Specification
Minimum standards for good quality guar gum have been defined in the United States FCC and by European Union Specifications as under:
Moisture: 14% max. Ash (total): 1.5% max.
Acid Insoluble Residue: 4% max.
Galactomannan: 75% min.
Protein: 7% max.
Arsenic: 3 ppm max.
Lead: 10 ppm max.
Zinc: 25 ppm max.
Copper & Zinc: 50 ppm max.
Guar Gum Components
Guar Gum mainly consists of hydrocolloidal polysaccharide with a high molecular weight, which consists of galactopyranose- and mannopyranose- units in glycoside linkage which can be chemically described as galactomannan.
Name of Guar Gum in different countries
English: Guar Gum
German: Guarkernmehl
French: Gomme Guar
Spanish: Goma Guar, Guaro Dervo
source : guargum.biz
Guar Gum Manufacturing
GuarGum Manufacturing
Depending upon the requirement of end product various processing techniques are used. In the commercial production of Guar gum is normally undertaken by using process of roasting, differential attrition, sieving and polishing.
Stage wise process of manufacturing food grade guar gum is as under.It is very important to select guar split in this process. Guar Gum split is screened to clean and soaked to prehydrate in a double cone mixer. Prehydrating stage is very important in process as it derives the rate of hydration of the final product.
Soaked splits, has reasonably high moisture content, is passed through Flacker. Flaked Guar 
split is grounded to desired particle size followed by drying of the material. The power is screened through rotary screens to deliver required particle size of Guar . Oversize is either recycled to main Ultra fine or regrinded in separate regrinding plant, as per viscosity requirement of Guar.
This stage helps to reduce the load at the grinder. The soaked splits are difficult to grind. Direct grinding of those generates more heat in the grinder which is not desired in the process as it results in insoluble or reduced hydration of the product. Through heating, grinding & polishing process the husk is separated from the endosperm halves and the refined Guar Gum split are obtained. Through grinding process the refined Guar split are then treated and converted into powder.
During split manufacturing process, husk & germ are obtained which are used as a cattle feed as they are rich in protein. It is widely sold in international market as “Guar Meal” and has contents of “Oil & Albuminoids”. These contents are about 50% in germ whereas it is about 25% in husks. Quality of food grade Guar gum powder is defined from its particle size, rate of hydration and microbial in it.
Guar Gum: Stage wise Process
Guar Seed
- First, Guar Pods are dried in sunlight, manually separated from the seeds.
- The Guar seeds are supplied to the industry for processing.
- Guar by-products, churi and korma are used for Cattle feed.
Undehusked Guar Splits
- The Guar gum is commercially extracted from Guar seeds essentially by
a mechanical process of roasting, differential attrition, sieving and polishing. - The seeds are broken and the germ is separated from the endosperm.
- Two halves of the endosperm are obtained from each seed and are known as Undehusked Guar Splits.
Refined Guar Splits
- Refined Guar Splits are obtained when the fine layer of fibrous material, which forms the husk, is removed and separated from the endosperm halves by polishing.
Guar Powder
The refined Guar Splits are then treated and finished into powders by a variety of routes and processing techniques depending upon the end product desired.Monday, May 24, 2010
Drilling Fluid Properties & Functions
I. Introduction
The rotary or air method of drilling is distinguished by two factors; (1) the bit is rotated or hammered against the bottom of the hole, and (2) a fluid and/or air is circulated down the hollow drill string, through the bit, and up the annulus removing the cuttings. The most common, fastest, and effective type of drilling in unconsolidated permeable formations is the mud rotary system. In consolidated rock formations, down hole hammer drilling using air, mist, or foam is the most advantageous and effective type of drilling. This paper focuses on the role of the circulating fluids as they relate to drilling function and fluid properties. The properties of a drilling fluid useful in performance one function may be detrimental to another. A proper understanding of drilling fluid's role, be it bentonite, polymers, or chemicals added to make up water as treatments or drilling fluid enhancement materials are essential for efficient, productive, and safe drilling.
II. Functions of a Drilling Fluid
A. Cool and lubricate the bit and drill string.
B. Clean the bottom of the hole beneath the bit
C. Transport cuttings to the surface.
D. Suspend drill cuttings in the annulus when circulation is stopped.
E. Drop off the cuttings at the surface.
F. Support the walls of the borehole.
G. Control subsurface pressure.
H. Stabilize the borehole.
To achieve these functions, the following side effects must be minimized.
A. Damage to subsurface formation, especially those that may be productive.
B. Reduction of the penetration rate.
C. Swab and circulation pressure problems.
D. Loss of circulation.
E. Erosion of the borehole.
F. Swelling of the sidewalls of the borehole creating tight spots and/or hole swelling shut.
G. Sticking of the drill pipe against the walls of the hole.
H. Retention of undesirable solids in the drilling fluid.
I. Wear on the pump parts.
III. Characteristics of a Drilling Fluid
A. Lubricity
B. Velocity
C. Viscosity
D. Density
E. Gel Strength
F. Filtrate Control
IV. Relationships Between Characteristics and Functions
A. Cool and Lubricate the Bit and Drill String
As the drill bit and drill string rotate in the borehole, they become hot due to friction. A
liquid fluidwill transfer heat from the bit and drill string, thereby cooling them. A drilling fluid that has
slickness or lubricity will lubricate the drill bit and drill pipe, reducing heat-causing friction.
B. Clean Beneath the Drill Bit
During circulation, the drilling fluid is ejected through jets at high velocity. This hydraulic
force strikes the bottom of the hole, blowing cuttings from beneath the bit and starting them up the annulus where the drilling fluid can then transport them to the surface. If the bottom of the hole is not cleaned of cuttings, the bit regrinds them, thus reducing the rate of penetration.
C. Transport, Suspend and Drop Off Cuttings
Once the cuttings are cleaned from the bottom of the hole, it is the drilling fluid's function
to transport them to the surface. To accomplish this, the drilling fluid must have a high enough viscosity (thickness) to transport the cuttings at minimum velocity from the mud pump. In transporting cuttings, increased viscosity can accomplish this task at reduced velocity. At the same time, decreased viscosity will require an increase in velocity. A drilling fluid should be mixed to a minimum viscosity and pumped at a minimum velocity that will still allow cutting removal. When drilling stops, for whatever reason, the drilling fluid must be able to suspend the cuttings, not allowing them to fall back down the annulus where they can collect around the drill bit. Once the cuttings reach the surface, they must be dropped off and not recalculate. If the cuttings are not dropped off, they will cause wear on the pump and increase pressure on the formation.
D. Support the Walls of the Hole
Lateral support of hole walls is removed as the bit drills a subsurface formation. Unless
the drilling fluid prior to the casing being set replaces the support, the formation will collapse into the borehole. The mechanism, depending on the characteristics of the drilling fluid and the nature of the formation being drilled, prevents this from occurring.
If the formation is very firm and consolidated (granite is an extreme example), little support by the drilling
fluid is required. If the formation is relatively firm and fairly consolidated (shale for example), sufficient support may be obtained solely from the density of the drilling fluid or drilling mud. If the formation is an unconsolidated permeable formation (sand, for example), the drilling fluid must have sufficient density (weight), and it must have the ability to form a thin deposition of particles (filter cake), on the walls of the borehole.
E. Control Pressure and Stabilize the Borehole
Two types of pressure are exerted on the borehole during drilling, formation pressure and
hydrostatic pressure. Formation pressure can collapse the borehole if it is not overcome by hydrostatic pressure pushing back against the formation. Hydrostatic pressure is the weight or density of the volume of drilling fluid or mud pushing against the formation. In order to have hydrostatic pressure, the drilling fluid must push back against the formation with minimal penetration into the formation. In unconsolidated permeable formations, the hydrostatic pressure occurs when the weight of the fluid is in contact with the impermeable deposits (filter cake) placed on the sides of the borehole by the drilling fluid. The filter cake and the hydrostatic pressure thereby control the formation pressure, reduce fluid loss and prevent caving,
resulting in hole stabilization.
V. Side Effects Minimized
A. Damage to Subsurface Formation
Almost any drilling fluid will alter the original characteristics of the formation it comes in
contact with, although some formations are more sensitive than others and some fluids are more
damaging. Damage to subsurface formations can take two forms; (1) reduced ability of a formation to produce water, and (2) reduced well bore stability. Damage to producing formations results from physical plugging by inert solids. The borehole can become unstable through chemical reactions (as in water-sensitive shale’s), or through physical erosion. Particularly sensitive formations may require special treatment of the fluid, or even a special fluid.
B. Reduction of Penetration Rate
The most significant factor affecting penetration rate is the difference between the
hydrostatic pressure of the drilling fluid and the formation pressure. Lower penetration rates are obtained if the density (weight) of the drilling fluid is much higher than the pressure gradient of the formation. To minimize hydrostatic pressure, the drilling fluid weight should be maintained at below 9 pounds per gallon of fluid. Excessive solid buildup and increased viscosity are factors that also lower penetration rates.
C. Swab and Circulation Pressure Problems
Swabbing (suction), and circulating pressure problems can be caused by a high viscosity, high solids content drilling fluid. A thick mud with high solids concentration reduces hydraulic
energy available at the bit, increases pump wear, slows circulation, and can create a suction when the drill pipe is extracted or pulled from the borehole. To prevent these problems, viscosity and mud weight should be checked and maintained as follows:
* Mud weights less than 9 lbs./gal.
* Viscosity 32 to 36 as measured by a marsh funnel and cup.
D. Loss of Circulation
Loss of circulation is one of the most serious problems to overcome in drilling. Loss of
circulation is partial or complete loss of the drilling fluid to the formation. Loss of circulation can occur due to naturally occurring fractures, crevices and channels. The driller has no control over these circumstances and must plug off the formation with a loss circulation material such as C/S Granular or Crumbles (bentonite). Loss circulation can also occur due to properties of the drilling fluid or mud. High viscosity, excessive density and high gel strengths can contribute to loss of circulation. To minimize this situation, frequent measurements of the drill mud should be taken. The density (weight) viscosity (thickness) and filtration (filter cake) should all be maintained at a minimum.
E. Erosion of the Borehole
Erosion of the borehole can occur when the drilling fluid is pumped at too great a velocity.
Erosion can occur at the drill bit where the jetting action causes erosion. It can also occur as the fluid comes into contact with obstacles while it moves up the borehole at a rapid rate. As the fluid comes into contact with obstructions, it can begin to rotate causing a swirling effect that can erode the side of the hole. To minimize erosion, viscosity and velocity of the fluid should be minimized.
F. Swelling of the Side Walls and Sticking Pipe
If the borehole walls are not maintained, the fluid is allowed to continually penetrate the
formation, and the hydration of native clays and shale are not minimized, the result will be tight spots and/or swelling shutting off the borehole. This is the result of a thick spongy filter cake or hydrated native clays. The result of either will be, in the worst case, stuck pipe. The simplest problem this causes is difficulty in coming out or going back into the borehole. It may necessitate redrilling through an already drilled formation. This reduces penetration rate and increases drilling time. To overcome this problem in unconsolidated formations, the use of a bentonite drilling mud (which seals off the formation with a thin impermeable filter cake) is advantageous. In swelling formations of native clay, the addition of polymers may be advantageous in that it coats the clays to prevent their swelling.
G. Retention of Undesirable Solids in the Drilling Fluid
There are two types of solids in a typical drilling mud. Functional or beneficial solids are,
added to the make up water in order for the drilling mud to perform certain functions. Sodium bentonite is most commonly used. Objectionable solids are those that are picked up by the drilling mud as it circulates inside the borehole. Sand and other formation cuttings are examples of objectionable solids. Objectionable solids perform no function and have adverse effects on the drilling program and the drilling equipment. Objectionable solids increase both density and viscosity of the drilling mud. This makes the drilling mud more difficult to pump and requires greater velocity to move the mud. It increases pressure on the formation, resulting in a thicker filter cake, etc. Objectionable solids must be removed either chemically or mechanically from the
drilling mud. Often, the addition of polymers to reduce gel strength of the drilling mud will aid in removal of cuttings. The best way to remove undesirable solids is to mechanically remove them through the use of a desander. If the solids are not removed, they will cause additional wear on the pump parts. By removing these solids, the maintenance on the mud pump and rebuilding of the mud pump will be minimized.
VI. Types of Drilling Fluids
A. Clay (bentonite)
B. Polymer
C. Foam
VII. Bentonite Clay
A. Advantages
i. High viscosity
ii. Low solids
iii. Suspends cuttings
iv. Fluid loss control
v. Stabilizes borehole
vi. Aids in prevention of lost circulation
B. Disadvantages
i. Retards settling of cuttings. The gel strength and viscosity properties of the
bentonite clay allow for cutting suspension and removal. This advantage of bentonite clay becomes a disadvantage in the settling of small cuttings and sand at the surface.
ii. In highly swelling clays and shale’s, the use of bentonite clay alone will not be
sufficient to prevent hydration and swelling of the formation.
iii. Bentonite is sensitive to water contamination. Hard water and salt water have
adverse effects on bentonite. Low pH and extremely high pH water will also affect the bentonite clay performance.
C. Overcoming Disadvantages
i. If the settling of cuttings becomes a problem in using bentonite clay, the addition
of small amounts of polymers will aid in this application. Polymers increase the viscosity of a bentonite clay mud. At the same time, no additional solids are being added, and the gel strength characteristic of the bentonite clay is reduced. This allows for better cutting removal. The best method for removing cuttings is the use of a desander. The desander removes a greater percentage of sand and cuttings than the addition of polymers, and does not change the properties of the bentonite clay. The use of a desander will increase the life of the bentonite clay. It will also reduce maintenance and repair of the mud pump.
ii. In clay and shale drilling, it is most important to seal off this formation and to
reduce hydration of the formation. Bentonite clay drilling mud cannot perform this function alone. Adding small amounts of polymer to the bentonite clay mud or switching to an all polymer drilling fluid system willoffset this problem. Polymers coat the clay or shale preventing hydration. Always add polymers to
hydrated bentonite not to the mix water. Adding polymers to the mix water will have the same effect on
the bentonite as it will on the clay formation, and the bentonite clay will not hydrate.
iii. Bentonite clay's performance as the water in which it affects a drilling mud is
mixed. The make up water is one of the main building blocks of the drilling mud. The pH, hardness, and
salt content of the make up water determine the yield and performance of the bentonite clay.
a. The pH of the make up water should be within the alkaline range. On
the pH scale, the acidity range is from less than 1 to just below 7. The alkalinity range is just above 7 to 14. A pH of 7 is considered neutral. The pH desired for mixing bentonite clay is between 8.5 and 10 on the pH scale. A pH of 9 is considered perfect. If the pH of the make up water is low, it will affect the hydration of the bentonite clay. The make up water should be treated with soda ash to raise pH. If the pH of the make up water exceeds 11 pH, flocculation of the bentonite clays can occur.
b. Hard water results in unsatisfactory performance of bentonite clay mud.
Hard water contains dissolved calcium salts. Calcium salts impair the suspending and sealing properties of bentonite clay. Soda ash is used to treat hard water usually 1 to 2 pounds of soda ash will be sufficient treat for both high pH and hardness.
c. Salt has a most adverse effect on bentonite clay. Salt will affect the bentonite clay in the mix water and if it comes into contact with it during drilling. Salt adversely affects filtration, suspension, viscosity, and gel properties of bentonite clay. If the salt is in the make up water,
the viscosity and gel development of the bentonite clay will be greatly reduced. Increased filtration and filter cake thickness will be accelerated. If the salt is encountered during drilling after freshwater hydration, the bentonite drilling mud will thicken. It will, over time, flocculate out the bentonite clay. There is no treatment for salt contamination. Bentonite clay should never be mixed in salt water. Find another water source for the mix water. If salt is encountered during drilling, the mud should be disposed of as it becomes contaminated, and fresh mud, made up in advance, should replace it. If the salt contamination within the formation is high or continuous, an alternate drilling fluid is advisable. Guar gum or Attapulgite clay mixed with dry polymer are two alternatives that perform well in salt conditions.
Note salt concentrations begin to adversely affect bentonite at 500 ppm. At 5000 ppm, bentonite should not be used.
VIII. Polymers
A. Dry Polymers
Dry polymers are non-toxic, non-fermenting organic polymers. There
are many advantages to Guar DColF20 material in conjunction with a bentonite clay mud.
Bentonite is very stable in the presence of DCOLF20. GuarPolymer increases lubricity, decreases fluid loss, increases viscosity, and inhibits water sensitive shale and clay formations from hydrating. Dry polymers perform well in hard and salty water, and do not deteriorate with age. Dry polymers contain much higher active ingredients than liquid polymers.
B. Natural Polymer (Guar Gum) -
Guar gum is natural occurring polymers in the form of a bean much like coffee beans.
The product is finely ground and used as a drilling fluid or additive due to its viscosifying abilities. The product works well in fresh or salt water. The product is subject to biological degradation because it will support biological growth. Like all polymers, guar gum is a poor filtrate control agent used alone. It also will not suspend cuttings when drilling stops. The product is sensitive to high temperatures and biological degradation. Mix waters should be low in temperature and free of enzymes and bacteria.
C. Liquid Polymers
Liquid polymers are polyacrylamide/polyacrylate emulsions kept in suspension with
mineral oil. Because the polymer is a liquid, it is much faster mixing than dry polymers. Because of this it is the product of choice in the groundwater industry. Liquid polymers are high in viscosity buildings, butlike all polymers, the product has poor filtration control when used alone. Liquid polymers work well in bentonite mud systems. They increase viscosity without increasing solids content of the mud. They increase lubricity and, working with bentonite, offer excellent fluid loss control. The liquid polymers are extremely sensitive to calcium and low pH water. The product is not as stable and has a much shorter shelf like than dry polymers. The primary function of Insta-Pac is as a clay shale formation hydration inhibitor. Secondary usage includes: use as a hydration inhibitor in mix water with granular bentonite for loss circulation material; use with bentonite clay as an aid to cuttings' removal; use as a low solid viscosifier with bentonite mud; and as an additive in foam drilling.
IX. Foam
When drilling in a consolidated formation, air drilling is typically used. The air drilling system
increases cutting rates in rock by carrying the cuttings away from the drill bit and up the hole. The formation is naturally stable. Therefore, a drilling fluid systems objective is to maintain circulation, lower hydrostatic head, and remove cuttings using the lowest volume of water and compressed air. This is typically done using air, water, foam, and stiff foam, in that order, depending on the formations encountered, depth of hole, diameter of hole, and size of cuttings. When foams drilling, use 1 to 2 pints per 100 gallons of make up water. This should be added to the foam-mixing tank. The foam/water mixture is injected into the air stream from the compressor through the mixing nozzle. The resulting foam is piped through the parts in the bit where it expands and flows back up the hole to the surface bringing with it suspended cuttings.
X. Chemicals
A. Sodium Carbonate (NaCO3) soda ash is used to precipitate soluble calcium from water
base mud’s to control pH. When the soda ash enters hard water, it ionizes as Na+ and CO3= in the continuous phase. The carbonate ions combine with the calcium ions, forming calcium carbonate (CaCO3), and inert precipitate. Treating hard water with soda ash prior to using the water to make a bentonite or polymer drilling fluid will result in a higher yield and more stable drilling fluid. Make up water should be treated with soda ash if 500-ppm calcium is present. Formula for soda ash addition is .001 x ppm Ca = lb. soda ash 42 gallons make up water. Excessive treatment with soda ash can cause high viscosity and gel strengths. If a mud has pH less than 11, soda ash additions will raise it.
B. Sodium Hydroxide (Caustic Soda)
A chemical primarily used to impart a higher pH. Caution is to be used when using
caustic. It can cause severe burns and it is highly corrosive. To raise pH, use ¼ to 1-pound Caustic per 50 gallons of water. Product is not recommended for use by groundwater drillers.
C. Sodium Acid Pyrophosphate
SAPP has a 4.5 pH in 10% solution. It is used as a thinning agent, to disperse sticky
clays and clean up and develop water-bearing formations. A very small amount of phosphate is required to thin clay-drilling fluids. Normally, ¼ to ½ pound per 50 gallons is adequate. To develop water well, use 4 to 10 pounds per 50 gallons of water, jetting and circulating product at the targeted water-bearing formation. The following phosphates can be used the same as SAPP:
* Sodium Hexametaphosphate - 6.8 pH
* Sodium Tetra phosphate - 8.0 pH
Care should be taken when using phosphate to develop water well. Development should
start and be completed at the time the phosphate is introduced to the system. Introducing phosphate into a system and letting it sit for 6 to 12 hours prior to well development can damage water-bearing formation inhibiting proper well development.
D. Lime
Lime (Ca[OH2]) has the same detrimental effect as cement has on drilling mud. Lime increases viscosity, gel strength and fluid loss in the formation. The reaction is very severe. Lime hinders the ability to develop a water-bearing formation properly.
E. Borax (Sodium Borate)
Used as a viscosifier and gelling agent in conjunction with guar gum .
F. Chlorine (Sodium Hypo chlorite-Liquid or Dry)
Chlorine is primarily used to destroy bacteria once the well is completed. It is also used
to destroy bacteria and enzymes in the mix water prior to using a guar gum (VariFlo) polymer.
XI. Mixing Drilling Mud
Attention should be given to the equipment used to mix drilling mud’s and to the sequence of
addition of the mud and any additives.
A. If the make up water requires treatment, always treat it prior to addition of the bentonite
clay.
B. Use a jet hopper mixer to disperse the bentonite clay.
C. Bentonite clay should be mixed slowly through the jet hopper at a rate of
one 50 lb. bag every 10 to 20 minutes.
D. Volume of mud pit should be three times the volume of the proposed hole. Figuring
volume of pit length (ft.) x width (ft.) x depth (ft.) x 7.5 = volume (gal).
E. The mud pit should be of such design that the drilling mud, during flow, changes direction
and slows, allowing for cuttings to drop out.
F. The addition of viscosifying polymers should be made after the bentonite clay mud is
thoroughly mixed in fresh water.
G. Viscosity and density tests should be run on the drilling mud following mixing. Periodic
tests should be made during drilling and changes noted. Sand content tests should be run on the mud once drilling starts.
The rotary or air method of drilling is distinguished by two factors; (1) the bit is rotated or hammered against the bottom of the hole, and (2) a fluid and/or air is circulated down the hollow drill string, through the bit, and up the annulus removing the cuttings. The most common, fastest, and effective type of drilling in unconsolidated permeable formations is the mud rotary system. In consolidated rock formations, down hole hammer drilling using air, mist, or foam is the most advantageous and effective type of drilling. This paper focuses on the role of the circulating fluids as they relate to drilling function and fluid properties. The properties of a drilling fluid useful in performance one function may be detrimental to another. A proper understanding of drilling fluid's role, be it bentonite, polymers, or chemicals added to make up water as treatments or drilling fluid enhancement materials are essential for efficient, productive, and safe drilling.
II. Functions of a Drilling Fluid
A. Cool and lubricate the bit and drill string.
B. Clean the bottom of the hole beneath the bit
C. Transport cuttings to the surface.
D. Suspend drill cuttings in the annulus when circulation is stopped.
E. Drop off the cuttings at the surface.
F. Support the walls of the borehole.
G. Control subsurface pressure.
H. Stabilize the borehole.
To achieve these functions, the following side effects must be minimized.
A. Damage to subsurface formation, especially those that may be productive.
B. Reduction of the penetration rate.
C. Swab and circulation pressure problems.
D. Loss of circulation.
E. Erosion of the borehole.
F. Swelling of the sidewalls of the borehole creating tight spots and/or hole swelling shut.
G. Sticking of the drill pipe against the walls of the hole.
H. Retention of undesirable solids in the drilling fluid.
I. Wear on the pump parts.
III. Characteristics of a Drilling Fluid
A. Lubricity
B. Velocity
C. Viscosity
D. Density
E. Gel Strength
F. Filtrate Control
IV. Relationships Between Characteristics and Functions
A. Cool and Lubricate the Bit and Drill String
As the drill bit and drill string rotate in the borehole, they become hot due to friction. A
liquid fluidwill transfer heat from the bit and drill string, thereby cooling them. A drilling fluid that has
slickness or lubricity will lubricate the drill bit and drill pipe, reducing heat-causing friction.
B. Clean Beneath the Drill Bit
During circulation, the drilling fluid is ejected through jets at high velocity. This hydraulic
force strikes the bottom of the hole, blowing cuttings from beneath the bit and starting them up the annulus where the drilling fluid can then transport them to the surface. If the bottom of the hole is not cleaned of cuttings, the bit regrinds them, thus reducing the rate of penetration.
C. Transport, Suspend and Drop Off Cuttings
Once the cuttings are cleaned from the bottom of the hole, it is the drilling fluid's function
to transport them to the surface. To accomplish this, the drilling fluid must have a high enough viscosity (thickness) to transport the cuttings at minimum velocity from the mud pump. In transporting cuttings, increased viscosity can accomplish this task at reduced velocity. At the same time, decreased viscosity will require an increase in velocity. A drilling fluid should be mixed to a minimum viscosity and pumped at a minimum velocity that will still allow cutting removal. When drilling stops, for whatever reason, the drilling fluid must be able to suspend the cuttings, not allowing them to fall back down the annulus where they can collect around the drill bit. Once the cuttings reach the surface, they must be dropped off and not recalculate. If the cuttings are not dropped off, they will cause wear on the pump and increase pressure on the formation.
D. Support the Walls of the Hole
Lateral support of hole walls is removed as the bit drills a subsurface formation. Unless
the drilling fluid prior to the casing being set replaces the support, the formation will collapse into the borehole. The mechanism, depending on the characteristics of the drilling fluid and the nature of the formation being drilled, prevents this from occurring.
If the formation is very firm and consolidated (granite is an extreme example), little support by the drilling
fluid is required. If the formation is relatively firm and fairly consolidated (shale for example), sufficient support may be obtained solely from the density of the drilling fluid or drilling mud. If the formation is an unconsolidated permeable formation (sand, for example), the drilling fluid must have sufficient density (weight), and it must have the ability to form a thin deposition of particles (filter cake), on the walls of the borehole.
E. Control Pressure and Stabilize the Borehole
Two types of pressure are exerted on the borehole during drilling, formation pressure and
hydrostatic pressure. Formation pressure can collapse the borehole if it is not overcome by hydrostatic pressure pushing back against the formation. Hydrostatic pressure is the weight or density of the volume of drilling fluid or mud pushing against the formation. In order to have hydrostatic pressure, the drilling fluid must push back against the formation with minimal penetration into the formation. In unconsolidated permeable formations, the hydrostatic pressure occurs when the weight of the fluid is in contact with the impermeable deposits (filter cake) placed on the sides of the borehole by the drilling fluid. The filter cake and the hydrostatic pressure thereby control the formation pressure, reduce fluid loss and prevent caving,
resulting in hole stabilization.
V. Side Effects Minimized
A. Damage to Subsurface Formation
Almost any drilling fluid will alter the original characteristics of the formation it comes in
contact with, although some formations are more sensitive than others and some fluids are more
damaging. Damage to subsurface formations can take two forms; (1) reduced ability of a formation to produce water, and (2) reduced well bore stability. Damage to producing formations results from physical plugging by inert solids. The borehole can become unstable through chemical reactions (as in water-sensitive shale’s), or through physical erosion. Particularly sensitive formations may require special treatment of the fluid, or even a special fluid.
B. Reduction of Penetration Rate
The most significant factor affecting penetration rate is the difference between the
hydrostatic pressure of the drilling fluid and the formation pressure. Lower penetration rates are obtained if the density (weight) of the drilling fluid is much higher than the pressure gradient of the formation. To minimize hydrostatic pressure, the drilling fluid weight should be maintained at below 9 pounds per gallon of fluid. Excessive solid buildup and increased viscosity are factors that also lower penetration rates.
C. Swab and Circulation Pressure Problems
Swabbing (suction), and circulating pressure problems can be caused by a high viscosity, high solids content drilling fluid. A thick mud with high solids concentration reduces hydraulic
energy available at the bit, increases pump wear, slows circulation, and can create a suction when the drill pipe is extracted or pulled from the borehole. To prevent these problems, viscosity and mud weight should be checked and maintained as follows:
* Mud weights less than 9 lbs./gal.
* Viscosity 32 to 36 as measured by a marsh funnel and cup.
D. Loss of Circulation
Loss of circulation is one of the most serious problems to overcome in drilling. Loss of
circulation is partial or complete loss of the drilling fluid to the formation. Loss of circulation can occur due to naturally occurring fractures, crevices and channels. The driller has no control over these circumstances and must plug off the formation with a loss circulation material such as C/S Granular or Crumbles (bentonite). Loss circulation can also occur due to properties of the drilling fluid or mud. High viscosity, excessive density and high gel strengths can contribute to loss of circulation. To minimize this situation, frequent measurements of the drill mud should be taken. The density (weight) viscosity (thickness) and filtration (filter cake) should all be maintained at a minimum.
E. Erosion of the Borehole
Erosion of the borehole can occur when the drilling fluid is pumped at too great a velocity.
Erosion can occur at the drill bit where the jetting action causes erosion. It can also occur as the fluid comes into contact with obstacles while it moves up the borehole at a rapid rate. As the fluid comes into contact with obstructions, it can begin to rotate causing a swirling effect that can erode the side of the hole. To minimize erosion, viscosity and velocity of the fluid should be minimized.
F. Swelling of the Side Walls and Sticking Pipe
If the borehole walls are not maintained, the fluid is allowed to continually penetrate the
formation, and the hydration of native clays and shale are not minimized, the result will be tight spots and/or swelling shutting off the borehole. This is the result of a thick spongy filter cake or hydrated native clays. The result of either will be, in the worst case, stuck pipe. The simplest problem this causes is difficulty in coming out or going back into the borehole. It may necessitate redrilling through an already drilled formation. This reduces penetration rate and increases drilling time. To overcome this problem in unconsolidated formations, the use of a bentonite drilling mud (which seals off the formation with a thin impermeable filter cake) is advantageous. In swelling formations of native clay, the addition of polymers may be advantageous in that it coats the clays to prevent their swelling.
G. Retention of Undesirable Solids in the Drilling Fluid
There are two types of solids in a typical drilling mud. Functional or beneficial solids are,
added to the make up water in order for the drilling mud to perform certain functions. Sodium bentonite is most commonly used. Objectionable solids are those that are picked up by the drilling mud as it circulates inside the borehole. Sand and other formation cuttings are examples of objectionable solids. Objectionable solids perform no function and have adverse effects on the drilling program and the drilling equipment. Objectionable solids increase both density and viscosity of the drilling mud. This makes the drilling mud more difficult to pump and requires greater velocity to move the mud. It increases pressure on the formation, resulting in a thicker filter cake, etc. Objectionable solids must be removed either chemically or mechanically from the
drilling mud. Often, the addition of polymers to reduce gel strength of the drilling mud will aid in removal of cuttings. The best way to remove undesirable solids is to mechanically remove them through the use of a desander. If the solids are not removed, they will cause additional wear on the pump parts. By removing these solids, the maintenance on the mud pump and rebuilding of the mud pump will be minimized.
VI. Types of Drilling Fluids
A. Clay (bentonite)
B. Polymer
C. Foam
VII. Bentonite Clay
A. Advantages
i. High viscosity
ii. Low solids
iii. Suspends cuttings
iv. Fluid loss control
v. Stabilizes borehole
vi. Aids in prevention of lost circulation
B. Disadvantages
i. Retards settling of cuttings. The gel strength and viscosity properties of the
bentonite clay allow for cutting suspension and removal. This advantage of bentonite clay becomes a disadvantage in the settling of small cuttings and sand at the surface.
ii. In highly swelling clays and shale’s, the use of bentonite clay alone will not be
sufficient to prevent hydration and swelling of the formation.
iii. Bentonite is sensitive to water contamination. Hard water and salt water have
adverse effects on bentonite. Low pH and extremely high pH water will also affect the bentonite clay performance.
C. Overcoming Disadvantages
i. If the settling of cuttings becomes a problem in using bentonite clay, the addition
of small amounts of polymers will aid in this application. Polymers increase the viscosity of a bentonite clay mud. At the same time, no additional solids are being added, and the gel strength characteristic of the bentonite clay is reduced. This allows for better cutting removal. The best method for removing cuttings is the use of a desander. The desander removes a greater percentage of sand and cuttings than the addition of polymers, and does not change the properties of the bentonite clay. The use of a desander will increase the life of the bentonite clay. It will also reduce maintenance and repair of the mud pump.
ii. In clay and shale drilling, it is most important to seal off this formation and to
reduce hydration of the formation. Bentonite clay drilling mud cannot perform this function alone. Adding small amounts of polymer to the bentonite clay mud or switching to an all polymer drilling fluid system willoffset this problem. Polymers coat the clay or shale preventing hydration. Always add polymers to
hydrated bentonite not to the mix water. Adding polymers to the mix water will have the same effect on
the bentonite as it will on the clay formation, and the bentonite clay will not hydrate.
iii. Bentonite clay's performance as the water in which it affects a drilling mud is
mixed. The make up water is one of the main building blocks of the drilling mud. The pH, hardness, and
salt content of the make up water determine the yield and performance of the bentonite clay.
a. The pH of the make up water should be within the alkaline range. On
the pH scale, the acidity range is from less than 1 to just below 7. The alkalinity range is just above 7 to 14. A pH of 7 is considered neutral. The pH desired for mixing bentonite clay is between 8.5 and 10 on the pH scale. A pH of 9 is considered perfect. If the pH of the make up water is low, it will affect the hydration of the bentonite clay. The make up water should be treated with soda ash to raise pH. If the pH of the make up water exceeds 11 pH, flocculation of the bentonite clays can occur.
b. Hard water results in unsatisfactory performance of bentonite clay mud.
Hard water contains dissolved calcium salts. Calcium salts impair the suspending and sealing properties of bentonite clay. Soda ash is used to treat hard water usually 1 to 2 pounds of soda ash will be sufficient treat for both high pH and hardness.
c. Salt has a most adverse effect on bentonite clay. Salt will affect the bentonite clay in the mix water and if it comes into contact with it during drilling. Salt adversely affects filtration, suspension, viscosity, and gel properties of bentonite clay. If the salt is in the make up water,
the viscosity and gel development of the bentonite clay will be greatly reduced. Increased filtration and filter cake thickness will be accelerated. If the salt is encountered during drilling after freshwater hydration, the bentonite drilling mud will thicken. It will, over time, flocculate out the bentonite clay. There is no treatment for salt contamination. Bentonite clay should never be mixed in salt water. Find another water source for the mix water. If salt is encountered during drilling, the mud should be disposed of as it becomes contaminated, and fresh mud, made up in advance, should replace it. If the salt contamination within the formation is high or continuous, an alternate drilling fluid is advisable. Guar gum or Attapulgite clay mixed with dry polymer are two alternatives that perform well in salt conditions.
Note salt concentrations begin to adversely affect bentonite at 500 ppm. At 5000 ppm, bentonite should not be used.
VIII. Polymers
A. Dry Polymers
Dry polymers are non-toxic, non-fermenting organic polymers. There
are many advantages to Guar DColF20 material in conjunction with a bentonite clay mud.
Bentonite is very stable in the presence of DCOLF20. GuarPolymer increases lubricity, decreases fluid loss, increases viscosity, and inhibits water sensitive shale and clay formations from hydrating. Dry polymers perform well in hard and salty water, and do not deteriorate with age. Dry polymers contain much higher active ingredients than liquid polymers.
B. Natural Polymer (Guar Gum) -
Guar gum is natural occurring polymers in the form of a bean much like coffee beans.
The product is finely ground and used as a drilling fluid or additive due to its viscosifying abilities. The product works well in fresh or salt water. The product is subject to biological degradation because it will support biological growth. Like all polymers, guar gum is a poor filtrate control agent used alone. It also will not suspend cuttings when drilling stops. The product is sensitive to high temperatures and biological degradation. Mix waters should be low in temperature and free of enzymes and bacteria.
C. Liquid Polymers
Liquid polymers are polyacrylamide/polyacrylate emulsions kept in suspension with
mineral oil. Because the polymer is a liquid, it is much faster mixing than dry polymers. Because of this it is the product of choice in the groundwater industry. Liquid polymers are high in viscosity buildings, butlike all polymers, the product has poor filtration control when used alone. Liquid polymers work well in bentonite mud systems. They increase viscosity without increasing solids content of the mud. They increase lubricity and, working with bentonite, offer excellent fluid loss control. The liquid polymers are extremely sensitive to calcium and low pH water. The product is not as stable and has a much shorter shelf like than dry polymers. The primary function of Insta-Pac is as a clay shale formation hydration inhibitor. Secondary usage includes: use as a hydration inhibitor in mix water with granular bentonite for loss circulation material; use with bentonite clay as an aid to cuttings' removal; use as a low solid viscosifier with bentonite mud; and as an additive in foam drilling.
IX. Foam
When drilling in a consolidated formation, air drilling is typically used. The air drilling system
increases cutting rates in rock by carrying the cuttings away from the drill bit and up the hole. The formation is naturally stable. Therefore, a drilling fluid systems objective is to maintain circulation, lower hydrostatic head, and remove cuttings using the lowest volume of water and compressed air. This is typically done using air, water, foam, and stiff foam, in that order, depending on the formations encountered, depth of hole, diameter of hole, and size of cuttings. When foams drilling, use 1 to 2 pints per 100 gallons of make up water. This should be added to the foam-mixing tank. The foam/water mixture is injected into the air stream from the compressor through the mixing nozzle. The resulting foam is piped through the parts in the bit where it expands and flows back up the hole to the surface bringing with it suspended cuttings.
X. Chemicals
A. Sodium Carbonate (NaCO3) soda ash is used to precipitate soluble calcium from water
base mud’s to control pH. When the soda ash enters hard water, it ionizes as Na+ and CO3= in the continuous phase. The carbonate ions combine with the calcium ions, forming calcium carbonate (CaCO3), and inert precipitate. Treating hard water with soda ash prior to using the water to make a bentonite or polymer drilling fluid will result in a higher yield and more stable drilling fluid. Make up water should be treated with soda ash if 500-ppm calcium is present. Formula for soda ash addition is .001 x ppm Ca = lb. soda ash 42 gallons make up water. Excessive treatment with soda ash can cause high viscosity and gel strengths. If a mud has pH less than 11, soda ash additions will raise it.
B. Sodium Hydroxide (Caustic Soda)
A chemical primarily used to impart a higher pH. Caution is to be used when using
caustic. It can cause severe burns and it is highly corrosive. To raise pH, use ¼ to 1-pound Caustic per 50 gallons of water. Product is not recommended for use by groundwater drillers.
C. Sodium Acid Pyrophosphate
SAPP has a 4.5 pH in 10% solution. It is used as a thinning agent, to disperse sticky
clays and clean up and develop water-bearing formations. A very small amount of phosphate is required to thin clay-drilling fluids. Normally, ¼ to ½ pound per 50 gallons is adequate. To develop water well, use 4 to 10 pounds per 50 gallons of water, jetting and circulating product at the targeted water-bearing formation. The following phosphates can be used the same as SAPP:
* Sodium Hexametaphosphate - 6.8 pH
* Sodium Tetra phosphate - 8.0 pH
Care should be taken when using phosphate to develop water well. Development should
start and be completed at the time the phosphate is introduced to the system. Introducing phosphate into a system and letting it sit for 6 to 12 hours prior to well development can damage water-bearing formation inhibiting proper well development.
D. Lime
Lime (Ca[OH2]) has the same detrimental effect as cement has on drilling mud. Lime increases viscosity, gel strength and fluid loss in the formation. The reaction is very severe. Lime hinders the ability to develop a water-bearing formation properly.
E. Borax (Sodium Borate)
Used as a viscosifier and gelling agent in conjunction with guar gum .
F. Chlorine (Sodium Hypo chlorite-Liquid or Dry)
Chlorine is primarily used to destroy bacteria once the well is completed. It is also used
to destroy bacteria and enzymes in the mix water prior to using a guar gum (VariFlo) polymer.
XI. Mixing Drilling Mud
Attention should be given to the equipment used to mix drilling mud’s and to the sequence of
addition of the mud and any additives.
A. If the make up water requires treatment, always treat it prior to addition of the bentonite
clay.
B. Use a jet hopper mixer to disperse the bentonite clay.
C. Bentonite clay should be mixed slowly through the jet hopper at a rate of
one 50 lb. bag every 10 to 20 minutes.
D. Volume of mud pit should be three times the volume of the proposed hole. Figuring
volume of pit length (ft.) x width (ft.) x depth (ft.) x 7.5 = volume (gal).
E. The mud pit should be of such design that the drilling mud, during flow, changes direction
and slows, allowing for cuttings to drop out.
F. The addition of viscosifying polymers should be made after the bentonite clay mud is
thoroughly mixed in fresh water.
G. Viscosity and density tests should be run on the drilling mud following mixing. Periodic
tests should be made during drilling and changes noted. Sand content tests should be run on the mud once drilling starts.
Friday, May 21, 2010
Fracture Fluids
The prim selection of fracturing liquid is one of the most blistering elements in Well Completion Services program. To select the prudish liquid, concerns such as fluid-loss command, crack conductivity, fabrication wrongdoing, and proppant instrumentality staleness be considered.Comprehensive investigation should be conducted to raise better knowing of fracturing-fluid conduct in treatments of high-permeability formations. The fluids are evaluated for fluid-loss properties, regained permeability (manufacture modification), and fracture conductivity. The results from these tests would provide in making the somebody disposable action for a bestowed symptomless. The results from various formation-damage tests and fracture-c
utile crosslinkedfluid system for Crack Culmination Services. The use of either a lengthwise gel or a crosslinked gel is underage on permeableness of fabrication, reservoir changeful and pool somatesthesia of mortal vessel.
Shaping impairment and hurt conductivity studies hump shown that breakers should be in root when fracturing high-permeability formations so that the total crosslinked gel product that leaks off into the formation can be effectively confused. Injury conductivity can be enhanced if an encapsulated quarrier is set in the proppant bundle .
utile crosslinkedfluid system for Crack Culmination Services. The use of either a lengthwise gel or a crosslinked gel is underage on permeableness of fabrication, reservoir changeful and pool somatesthesia of mortal vessel.
Shaping impairment and hurt conductivity studies hump shown that breakers should be in root when fracturing high-permeability formations so that the total crosslinked gel product that leaks off into the formation can be effectively confused. Injury conductivity can be enhanced if an encapsulated quarrier is set in the proppant bundle .
fracture fluids in Drilling
Drilling fluids or liquids perform a variety of functions that
influence the drilling rate, the cost, efficiency and safety of drilling
operations. There are many types of drilling fluid systems available
like water base muds, oil base muds, stable foam muds, air
or gas base muds from which the right system may be chosen.
Main drilling mud additives include viscosifying agents, fluid loss
control agents, drilling fluid dispersants and corrosion inhibitors.
Cement and cement additives are considered to be critical inputs
in the completion of any oil and gas well. The increase in demand
for cement suitable for oil and gas wells led to the establishment
of API codes by the American Petroleum Institute and nine classes
of cements for the oil industry have been classified. Two of the
nine classes of cements, the classes G and H, are called basic
oil well cements. Main cement additives retarders, turbulence
inducers and fluid loss controlling agents.
influence the drilling rate, the cost, efficiency and safety of drilling
operations. There are many types of drilling fluid systems available
like water base muds, oil base muds, stable foam muds, air
or gas base muds from which the right system may be chosen.
Main drilling mud additives include viscosifying agents, fluid loss
control agents, drilling fluid dispersants and corrosion inhibitors.
Cement and cement additives are considered to be critical inputs
in the completion of any oil and gas well. The increase in demand
for cement suitable for oil and gas wells led to the establishment
of API codes by the American Petroleum Institute and nine classes
of cements for the oil industry have been classified. Two of the
nine classes of cements, the classes G and H, are called basic
oil well cements. Main cement additives retarders, turbulence
inducers and fluid loss controlling agents.
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