Bit Technology- Heat Treating

Heat Treating
The desired metallurgical properties and physical strengths are developed
through heat treating. As mentioned above, the strength is improved by
increasing the carbon content at the surface by carbonizing, commonly
known as “case hardening”. This is essential for the teeth on milled tooth
bits, and necessary for strength and wear resistance on the bearing surfaces.
Toughness (resistance to impact and crack propagation) is attained by
leaving the inner part or the “core steel” unchanged.
The overall physical properties that are needed (strength and toughness)
are achieved by heating the parts to a high temperature, then quenching
them in oil. The maximum surface hardness of the carbonized section gets
about 60 - 64 Rc (the hardness of a file). The core hardness will be about 25
- 40 Rc, remaining tough and ductile.
Mill Tooth Bit Teeth
The teeth on a mill tooth bit are sometimes “hard-faced” using tungsten
carbide. This hard-facing can be on the gauge teeth (for hard formations),
the inner teeth (for soft formations), or on both rows. Hard-facing is
applied in such a way so that, as the teeth dull, the hard-facing causes a
self-sharpening of the tooth.
Insert Bits
Over the past ten years, most of the progress in rolling cutter bits has been
made in the design of insert bits. Although the merits of tugsten carbide
bits has long been accepted, it was not until recently that bit manufacturers
obtained enough experience with the carbide material and design to make it
possible to consider this type of bit for application in virtually all
formations - soft, medium and hard.
The chief advantage of this concept is that there is virtually no change in
the configuration of the cutting structure due to wear. In addition, any bit
often finds good application in a variety of formations. Thus, the limiting
factor on performance is usually the life of the bearing assembly (providing
formation changes do not cut short the bit run).
The basic principles governing insert-type bit designs are the same as those
applied to milled tooth design, desired depth of tooth interfit, insert
extension, cone shell thickness, cone diameter, and gauge requirements.
Of primary importance is the proper grade of carbide material used in the
inserts. Much has been learned in this respect since the initial model was
placed on the market. Experience has shown the need for carbide materials
of various grades, dictated largely by the design purpose of the cutting
structure.
At present, the manner in which insert bits now function closely parallels
the mechanics of the three major categories of milled tooth bits, soft
(gouging/spading), medium (chipping plus limited penetration), and hard
(crushing/fracturing). For this reason, the composition as well as the
configuration of the insert material is being subjected to constant
evaluation and improvement. To date, the ultimate in both areas has not
been determined.

Bit Technology- Material Requirements

Material Requirements


The rock bit must be stronger than the rock it is to drill. The measurement
of hard steel is measured on the “Rockwell” hardness tester scale (Rc). The
tester uses a diamond pyramid indenter with a load of 150 kilograms. The
deeper the indentation in the steel, the softer it is.
The degree of hardness that can be produced in steel is determined by its
carbon content, the higher the percentage of carbon (up to 0.7%), the
harder the steel. By heat treating properly, it can be made up to about 65
Rc. Alloying elements improve the hardening potential in thick sections
and cause the steel to have a more uniform response to heat treating. The
steel must also be ductile (resistance to crack propagation). This ductility
or “toughness” of metals is inversely related to hardness (the harder a
metal, the less ductile. The softer the steel, the more ductile). Alloying
elements improve the ductility of steels and toughness, and resistance to
failure from impact loads.

Bit Technology- Bearing Systems

Bearing Systems


The first type of bearing system used with roller cone bits was a nonsealed,
roller-ball-friction bearing arrangement, utilizing rollers on the heel
of the journal. The primary load, or stress was exerted on these rollers, and
drilling fluid was used to lubricate the bearings. Bearing size was
maximized, since room for a seal was not required. The bearing surfaces
were machined and ground to very close tolerances to ensure dependable
service. This type of bearing system is also available with modifications for
air circulation and for use with a percussion hammer (Figure 3-6a).
The next generation of bearing systems was a sealed roller bearing system,
having a sealed grease reservoir to lubricate the bearings. The bearing
system is composed of: 1) a roller-ball-friction or roller-ball-roller bearings
2) the seal, which retains the lubricant and prevents drilling fluid and
abrasive cuttings from entering the bearing cavities, 3) the shirttail is
designed and hardfaced to protect the seal, 4) a lubricant, an
elasto-hydrodynamic type, is used to ensure minimum friction and wear, 5)
the reservoir, which stores and supplies the lubricant to the bearings, and 6)
the vented breather plug, which transfers downhole fluid pressure against
the lubricant-filled flexible diaphragm to equalize pressures surrounding
the bearing seal (Figure 3-6b).

 

Figure 3-6a                   Figure 3-6b
There is, however, one serious drawback to the roller-ball-roller bearing
system. The primary cause of roller bearing failure is journal spalling,
which causes destruction of the rollers and the locking of the cone.
To remedy this, instead of the standard roller bearing assembly, the
“journal bearing” system utilizes solid metal bushings for direct cone to
journal contact. This offers a distinct mechanical advantage over roller
arrangements in that it presents a larger contact area at the load bearing
point. This distribution of the load eliminated the chief cause of roller
bearing assembly failure - spalling in the load portion of the bearing face.
Journal bearing systems in the tungsten carbide insert bits features a metal
bearing surface combined with a hardfaced journal and a lubricant.
Specialized seals and reliable pressure equalization systems keeps the
drilling fluid and formation contaminants out of bearings, and positively
seals the graphite-based lubricant inside the bearing. Precision fit of the
journal and cone distributes contact loading evenly throughout a nearperfect
arc. Bearing surfaces are finished to a carefully controlled surface
texture to ensure optimum lubrication.
The manufacturing of the journal bearing system consists of having the
journals either milled, grooved or pressed (depending on the bit company)
to accommodate the bushing. Then the bushings are inlaid on the journal.
Once the cone is fitted with teeth and gauge protection, the journal is then machine-pressed into the cone. To complete the seal between the cone and
the journal, special rings (seals) have been developed.
Seals
The first and still most popular seal is the radial seal (used mainly on the
sealed roller bearing bits). The radial seal is a circular steel spring encased
in rubber, which seals against the face of the shank and the face of the
cone. The newer “O” ring seal is considered the most effective seal. The
major problem confronting the “O” ring is tolerance, which must be precise
in order to maintain an effective seal.
An understanding of lubricants and lubricating systems is necessary for
successful drilling operations. The lubricating systems are essentially the
same, and are composed of an external equalizer located under the bit or on
back of the shanks, a grease reservoir with some sort of expandable
diaphragm to distribute the grease, and some sort of distribution system to
the bearings. In addition, there is a pressure relief valve to release any
trapped pressure, which might otherwise rupture the seals.
Pressure surges can be detrimental to these sealed systems. As pressure and
temperature increase, the viscosity of the lubricant increases. As a result,
the system cannot instantaneously compensate for abrupt changes in
pressure due to surges (going into the hole, making connections, etc.) and
small quantities of mud invade the system. With the close tolerance
necessary for effective sealing, mud solids can be damaging.
Adequate cleaning is even more important with sealed bearing bits. If
drilled cuttings are allowed to build up around the shirttail, seal damage
and premature bearing failure may result. Gauge protection is also
important to seal and bearing life, because seal damage can occur from
shirttail wear caused by inadequate gauge protection.
Any time a sealed bearing bit is rerun, the seals and shirttail should be
carefully checked for excessive wear or grooving.
To complete the journal-cone assembly, a positive seal is required to keep
drilling fluid out, while allowing the graphite lubricant in, which keeps the
bearings from overheating. The positive seal requires a relief valve to allow
escape of excess pressure, which can overload the seal and cause seal
failure.

Bit Technology- Cutting Structures - Gauge Protection

Gauge Protection


Protection of the gauge surface is vital to the effectiveness of any bit. The
gauge surfaces constantly ream the hole, and thus are subject to continuous
abrasive wear.
Applying tungsten carbide in a steel matrix through a welding process,
called “hardfacing”, provides the best resistance to this type of wear.
Gauge protection is improved as the amount of hardfaced surface area
increases.
The configuration of the gauge teeth determines the available surface area.
The “A” type teeth are standard for soft formation bits, resulting in
minimum gauge protection for drilling medium-hard formations. The “T”
type teeth provides the greatest amount of surface area for the application
of hard metal, and are used for abrasive formation bit types.
For work in very hard formations, a flat-top tungsten carbide insert is
pressed into the gauge surface for additional protection.
Gauge protection is specified in roller cone bits by adding a “G” to the
IADC code.

Bit Technology- Cutting Structures - Tungsten Carbide Cutting Structures

Tungsten Carbide Cutting Structures


Since most of the basic design features of the mill tooth cuttings structures
have been incorporated into insert bits, the main variations occur in insert
shape (Figure 3-5).



Figure 3-5: Tungsten Carbide Tooth Shapes
Historical shapes of milled teeth have built up a mystique about insert tooth
shape. Many people in the oil field thought that chisel shaped teeth
significantly affected the drill rate in all formations. This was because early
drilling practices used light bit weights, causing the relatively sharp chisel
shaped inserts to have a higher unit loading on the formation, hence faster
drill rates. When heavier bit weights are used, it tends to nullify the
advantage of the chisel shape. Even the steel milled teeth break down under
heavy weights. In fact, most bits drill 75% of the hole in a 1/2 to 3/4 dull
condition. With this in mind, many “blunt” insert tooth designs were made,
and seem to drill efficiently. Nowadays, most insert teeth have this blunt,
conical shape.

Bit Technology- Cutting Structures - Steel Tooth Cutting Structures

 Steel Tooth Cutting Structures


There are three basic design features incorporated in steel tooth cutting
structures, teeth spacing, tooth hardfacing, and tooth angle (Figure 3-4).
Using variations of these parameters, bits are separated into formation
types.







Soft Formation Cutting Structures
Teeth on this type of bit are few in number, widely spaced,
and placed in a few broad rows. They tend to be slender, with
small tooth angles (39° to 42°). They are dressed with hard
metal.
Medium Formation Cutting Structures
Teeth on medium formation bits are fairly numerous, with
moderate spacing and depth. The teeth are strong, and are a
compromise between hard and soft bits, with tooth angles of
43° to 46°. The inner rows as well as the gauge rows are
hardfaced.
Hard Formation Cutting Structures
There are many teeth on this type of bit. They are closely
spaced and are short and blunt. There are many narrow rows
with tooth angles of 46o to 50o. The inner rows have no
hardfacing, while the gauge row is hardfaced.

Bit Technology- Cutting Structures

Cutting Structures

In 1909, when roller cone bits were introduced into the oilfield, the drag bit
was replaced by the roller cone’s steel tooth cutting structure. These steel
(milled) teeth have undergone changes in height, number per cone, and
thickness, to accommodate the various types of formations.
When harder formations tended to “eat up” the steel teeth, a different
cutting structure was needed, and in 1949 the first insert bit was used.
Introduced by Hughes Tool Company and nicknamed the “The Chert Bit”,
it brought on-bottom drilling hours up from 5 hours to 30 hours or more.
Many of the design features in the milled tooth bits were incorporated into
insert bits.

Bit Technology- Circulation Systems - Jet Nozzles

Jet Nozzles


There are essentially three types of jet nozzles used in tri-cone bits.
Shrouded nozzle jets provide maximum protection against retainer ring
erosion, excessive turbulence or extended drilling periods. Standard jet
nozzles are easier to install and are recommended for situations where
erosion is not a problem. Air jet nozzles (see above) are used on bits
designated for drilling with air or gas.
Nozzle sizes play an important role in bit hydraulics. The benefits of the
correct selection include effective hole cleaning and cuttings removal,
faster drill rates and thus lower drilling costs.
Orifice sizes are stated in 1/32 inch increments, with the most common
being between 10/32 to 14/32 sizes. Directional bit jets are available in
sizes from 18/32 to 28/32.

Bit Technology- Circulation Systems - Air or Gas Circulation Bits

Air or Gas Circulation Bits


A third type of circulation medium is compressed air or gas, and can be
used with either regular or jet circulation bits. Bits manufactured for air or
gas circulation have special passageways from the bore of the bit to the
bearings, through which a portion of the air or gas is diverted to keep the
bearings cool and purged of dust or cuttings. From the special passageways
to the bearings, the air or gas passes through a number of strategically
located ports or holes in the bearing journal, flows through the bearing
structure and exhausts at the shirttail and gauge of the bit, to flow up the
annulus.  

Bit Technology- Circulation Systems - Regular Circulation Bits

Regular Circulation Bits




Regular circulation bits (Figure 3-3a), have one to three holes drilled in the
dome of the bit. Drilling fluid passes through the bore of the bit, through
the drilled holes, over the cutters, and then to the bottom of the hole, to
flush away the drill cuttings.

Bit Technology- Circulation Systems

Circulation Systems


The first hydraulic features incorporated into drilling tools dated back to
the original use of hollow drillpipe with direct circulation of drilling fluids.
As the first fishtail bits became popular, around the turn of the century,
circulation though water courses was used for the first time. The first
rolling cutter rock bits of 1909 introduced a central water course system
which directed fluid discharge towards the cutters.
In 1942, rock bits with jet nozzles were introduced to the oil industry. The
“jet bit” concept is considered to be the major hydraulic design
improvement in drill bits and remains state-of-the-art.
Further improvements in the circulation systems include extended nozzle
bits, seven to twelve nozzles in PDC bits, and the various water courses in
diamond bits.

Bit Technology- Interfitting Teeth and Cone Offset

Interfitting Teeth and Cone Offset

The idea of interfitting teeth (Figure 3-2a), makes it possible to have large bit parts, and allows the inner row of teeth to cut new formation on each rotation. Interfitting also offers some degree of self-cleaning. One result of this interfitting is that each of the three cones are different.

Cone offset (Figure 3-2b), is caused by the journal centerline not intersecting the bit centerline (or bit center of rotation). The distance that the journal centerline misses the bit centerline (measured perpendicular to the journal centerline at the center of rotation) is the offset.

The skew point is an arbitrary point along the journal centerline and is the angle formed by the offset, the centerline of the journal, and a line from the bit center to the skew point. The skew direction is always “positive”, or in the direction of rotation. This permits the tips of the teeth to “ream” the hole to full gauge. “Negative” skew would have the gauge face rubbing the hole wall, increasing gauge wear.

As with the journal angle, the offset will be different in each type of formation. In soft formation bits, the maximum offset (3o skew angle) is used to increase the gouging, scraping action. Medium formation bits add a limited offset (2o skew angle) to develop cutter action. While hard formation bits have no offset, to minimize gouging and scraping.

Bit Technology- Journal Angle

Journal Angle

One of the basic design fundamentals of rolling cutter rock bits is the journal angle. Though this angle may vary from one rock bit type to the next, in each bit the three journal angles are all identical.
The journal angle (Figure 3-1) is the angle at which the journal is mounted, relative to a horizontal plane. This mounting moves the cutting elements (cones) outside the support members. The journal angle also controls the cutter profile or pattern it drills, and it affects the amount of cutter action on
the bottom of the hole.

Journal angles are different for each “type” of formation:

Soft Formations

Journal angle (33o) - this allows a cutter profile which accentuates cutter action and permits greater tooth depth.

Medium Formations

Journal angle (34o to 36o), to decrease cutter action.

Hard Formations

Uses a large journal angle (39o), to minimize cutter action.

Bit Technology - Rolling Cutter Rock Bits

Rolling Cutter Rock Bits

The first successful rolling cutter rock bit was introduced into the oil field by Howard Hughes Sr. in 1909. Over the next fifteen years, the rolling cutter bit was used primarily in hard formation areas. This rolling cutter bit was a two-cone bit with cones that did not mesh, consequently, the bit had a tendency to “balled-up” in soft shales. The bit was redesigned with meshing teeth (self-cleaning) in the 1920s and in the early 1930’s, the tricone bit was introduced with cutters designed for hard and soft formations.

The primary drilling mechanism of the rolling cutter bits is intrusion, which means that the teeth are forced into the rock by the weight-on-bit, and pulled through the rock by the rotary action. For this reason, the cones and teeth of rolling cuttings rock bits are made from specially, case hardened steel.

One advantage of a rolling cutter bits is the three bearing design located around the journal of the bit. Heel bearings are roller bearings, which carry most of the load and receive most of the wear. Middle bearings are ball bearings, which hold the cone on the journal and resist thrust in either direction. The nose bearing consists of a special case hardened bushing pressed into the nose of the cone and a male piece, hard faced with a special material, to resist seizure and wear.

Although rock bits have been continually improved upon over the years, three developments remains outstanding: (1) the change in water course design and the development of the “jet” bit, (2) the introduction of the tungsten carbide insert cutting structure, and (3) the development of sealed journal bearings.

Bit Technology

Bit Technology

Upon completion of this chapter, you should be able to:

• Describe the components of roller cone and fixed cutter bits and understand why these variations are advantageous in certain situations.

• Determine the appropriate type of bit for a future bit run, given the previous bit performances.

• Describe the various types of fixed cuter bits.

• Explain why running procedures are different for fixed cutter bits.

Cement Additives

Cement Additives

Accelerators

An accelerator is a chemical additive used to speed up the normal rate of reaction between cement and water which shortens the thickening time of the cement, increase the early strength of cement, and saves time on the drilling rig. Cement slurries used opposite shallow, low-temperature formations require accelerators to shorten the time for "waiting-oncement". Most operators wait on cement to reach a minimum compressive strength of 500 psi before resuming drilling operations. When using accelerators, this strength can be developed in 4 hours. It is a good practice to use accelerators with basic cements because at temperatures below 100oF, neat cement may require 1 or 2 days to develop a 500 psicompressive strength.

Common accelerators are sodium metasilicate, sodium chloride, sea water, anhydrous calcium chloride, potassium chloride and gypsum.

Retarders

Neat cement slurries set quickly at a BHT greater than 110oF. A retarder is an additive used to increase the thickening time of cements. Besides extending the pumping time of cements, most retarders affect the viscosity to some degree. The governing factors for the use of retarders are temperature and depth. Common retarders are lignosulfonates, modified cellulose, organic acids, organic materials and borax.

Extenders

Extended cement slurries are used to reduce the hydrostatic pressure on weak formations and to decrease the cost of slurries. Extenders work by allowing the addition of more water to the slurry to lighten the mixture and to keep the solids from separating. These additives change the thickening times, compressive strengths and water loss. Common extenders are fly ash, bentonite, and diatomaceous earth. 

Pozzolans

Pozzolans are natural or artificial siliceous materials added to portland cement to reduce slurry density and viscosity. The material may be either a volcanic ash or a clay high in silica. The silica in the pozzolans combines with the free lime in dry cement, which means a soluble constituent is removed from the cement and the new cement is made more resistive. Common pozzolans are diatomaceous earth and fly ash.

Cementing Nomenclature

Cementing Nomenclature

Casing Centralizers

Centralizers assist in the removal of filter cake and displacement of drilling fluid by providing a more uniform flow path for the cement slurry. Close scrutiny of the mudlog and wireline logs will help in the placement of centralizers. Zones of increased permeability, doglegs and areas of key seating, should have centralizers placed around the casing

Wall Scratchers

These are most useful when running casing through a high fluid-loss drilling fluid. There are two types of wall scratchers, rotating scratchers used when the casing can be rotated (normally in vertical wells), and reciprocating scratchers used when the pipe is reciprocated (moved up and down). When these scratchers are placed in 15 to 20 foot intervals, overlapping cleaning occurs.

Wiper Plugs

Both top and bottom plugs are used during cementing operations. They are used to separate the various fluids from one another. The red bottom plug has a shallow top, is made of rubber, and has a hollow core. It is used ahead of the cement slurry to prevent cement/drilling fluid contamination and to clean the casing wall of filter cake. After the bottom plug comes into contact with the float valve, sufficient pressure (150 to 350 psi) causes the top diaphragm to rupture, allowing the cement slurry to

flow through it. The black top plug has a deep cup on its top and has a solid, molded rubber core. It is dropped after the cement slurry has been pumped, to prevent contamination with the displacement fluid. The top plug also signals the end of displacement by forming a seal on top of the bottom plug, causing a pressure increase.

Chemical Washes

Chemical washes are fluids containing surfactants and mud thinners, designed to thin and disperse the drilling fluid so that it can be removed from the casing and borehole. Washes are available for water-based and oil-based drilling fluids. They are designed to be used in turbulent flow conditions.

Spacers

Spacers are fluids of controlled viscosity, density and gel strength used to form a buffer between the cement and drilling fluid. They also help in the removal of drilling fluid during cementing.

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Removal of the Drilling Fluid

Removal of the Drilling Fluid
For cementing operations to be successful, all annular spaces must be filled with cement, and the cement properly bonded to the previous casing and formation. In order for this to occur, all the drilling fluid must be displaced by the cement slurry. This is not always an easy matter, because there are several factors which affect the removal of the drilling fluid:

• washouts in the open hole, making it difficult to remove drilling fluid and filter cake
• crooked holes, making casing centralization difficult and drilling fluid not being removed from the low side
• poorly treated drilling fluids having high fluid losses Good drilling practices will not assure a good cement job, but they may help prevent a failure. The ideal drilling fluid for cementing operations should have:

• a low gel strength, with low PV and low YP
• a low density
• a low fluid loss
• a chemical make-up similar to the cement

Since these conditions are very seldom met, fluid washes and spacers are usually pumped ahead of the cement to remove as much drilling fluid as possible.

Cement Slurries

Cement Slurries

Water is added to dry cement to cause hydration and to make a pumpable

slurry. To be used correctly, several properties must be known: the yield per unit (cubic feet per sack), the amount of water required (gallons per sack), and its density (pounds per gallon).

Another important parameter is the cements “absolute volume”. This is the actual volume occupied by the material (the bulk volume includes the open spaces between the cement particles). For example, one sack (94 lbs) of cement has a bulk volume of 1 ft3, but if all the open spaces between the particles were removed, the absolute volume would be 0.478 ft3.

With dry materials (cement and additives), the absolute volume is used along with the water requirements to determine the slurry. For example, the absolute volume of one sack of cement (0.478 ft3) plus the water volume (5.18 gal/sk or 0.693 ft3) yields a slurry volume of 1.171 ft3 (0.478 +

0.693).

The absolute volume of the cement's components are normally found in tables, but may be calculated using:

For components that dissolve in water (sodium chloride, etc.), since they do not occupy as much space as the specific gravities would indicate, the absolute volume is determined from experimental data and placed. Slurry density is also determined. Since one sack of cement weighs 94 lbs, and 0.693 ft3 of water weighs 43.2 lbs, when mixed they yield 137.2 lbs of slurry. The slurry's density is then calculated by dividing slurry weight by slurry volume, 137.2 lbs / 1.171 ft3 equals 117.1 lbs/ft3 (15.7 ppg). Yield is converted to cubic feet per sack by using the constant 7.4805 (62.4

lbs/ft3 / 8.34 lbs/gal).

Fly ash, a synthetic pozzolan, is another major constituent of cements. A fly ash/cement mixture is designated as the ratio of fly ash to cement (expressed as 50:50 or 60:40, etc.) with the total always equaling 100. The first number is the percentage of fly ash (74 lbs/sack), the second number is cement (94 lbs/sack). A sack of fly ash and a sack of cement have the same absolute volume.

If other additives are included (gel, accelerators, retarders, etc.), the mixture is expressed as a percentage of weight of both cement and fly ash. The slurry is then expressed: 50:50:2% gel

Cementing Introduction

Cementing
Introduction

Oil well cementing is the process of mixing and displacing a slurry down the casing and up the annulus, behind the casing, where is allowed to “set”, thus bonding the casing to the formation. Some additional functions of cementing include:

• Protecting producing formations
• Providing support for the casing
• Protecting the casing from corrosion
• Sealing off troublesome zones
• Protecting the borehole in the event of problems

The main ingredient in most cements is “Portland” cement, a mixture of limestone and clay. This name comes from the solid mixture resembling the rocks quarried on the Isle of Portland, off the coast of England.

All cement is manufactured in essentially the same way. Calcareous and argillaceous materials (containing iron and aluminum oxides) are finely ground and mixed in correct proportions, either in a dry condition (dry processing) or with water (water processing). The mixture is then fed into the upper end of a sloping kiln at a uniform rate. The kiln is heated to temperatures from 2600o to 3000oF. As the mixture falls to the lower end, the mixture melts and chemical reactions occur between the raw materials.

When the mixture cools, it is called “clinker”. The clinker is then ground with a controlled amount of gypsum (1.5 to 3.0% by weight), to form portland cement.

The principle compounds resulting from the burning process are Tricalcium Silicate (C3S), Dicalcium Silicate (C2S), Tricalcium Aluminate(C3A), and Tetracalcium Aluminoferrite(C4AF). contains more information on the properties of these compounds. These materials are in an anhydrous form. When water is added, they convert to their hydrous form, which is then called a “cement slurry”.
The American Petroleum Institute (API) has established a classification system for the various types of cements, which must meet specified chemical and physical requirements. classifications and their applications to depths of 16,000 ft. (4880 m), under various temperature and pressure conditions.

Casing Couplings

Casing Couplings

Couplings are short pieces of casing used to connect the individual joints. They are normally made of the same grade of steel as the casing. Through their strength can be different than the casing. The API has specifications for four types of couplings.

• Short round threads and couplings (CSG)

• Long round threads and couplings (LCSG)

• Buttress threads and couplings (BCSG)

• Extremeline threads (XCSG)

The CSG and LCSG have the same basic thread design. The threads have a rounded shape, with eight threads per inch. These threads are generally referred to as API 8-round. The only difference between the two is that the LCSG has a longer thread run-out, which offers more strength for the connection. LCSG are very common couplings.

Buttress (BCSG) threads are more square, with five threads per inch. They are also longer couplings, with corresponding longer thread run-out. The XCSG (Extremeline) couplings are different from the other three connectors in that they are integral connectors, meaning the coupling has both box and pin ends.

Coupling threads are cut on a taper, causing stress to build up as the threads are made up. A loose connection can result in a leaking joint. An over-tight connection will result in galling, which again, will cause leaking. Proper make-up is monitored using torque make-up tables and the number of required turns.

A special thread compound (pipe dope) is used on casing couplings, each type of coupling having its own special compound. Many companies have their own couplings, in addition to the API standards, which offer additional features not available on the API couplings.

Casing properties

Casing properties are defined as:

• Yield Strength: The tensile stress required to produce a total elongation of 0.5% per unit length

• Collapse Strength: The maximum external pressure or force required to collapse the casing joint

• Burst Strength: The maximum internal pressure required to cause a casing joint to yield

Casing dimensions are specified by its outside diameter (OD) and nominal wall thickness. Normal wellsite conventions specify casing by its OD and weight per foot. As stated earlier, one should specify which weight one is referring to, though most often it is the nominal weight.

Casing Standards

Casing Standards

The American Petroleum Institute (API) has developed certain standards and specifications for oil-field related casing and tubing. One of the more common standards is weight per unit length. There are three “weights” used:

• Nominal Weight: Based on the theoretical calculated weight per foot for a 20 ft length of threaded and coupled casing joint.
• Plain End Weight: The weight of the joint of casing without the threads and couplings.
• Threaded and Coupled Weight: The weight of a casing joint with threads on both ends and a coupling at one end.

The Plain End Weight, and the Threaded and Coupled Weight are calculated using API formulas. These can be found in API Bulletin 5C3. API standards include three length ranges, which are:

• R-1: Joint length must be within the range of 16 to 25 feet, and 95% must have lengths greater than 18 feet
• R-2: Joint length must be within the range of 25 to 34 feet, and 95% must have lengths greater than 28 feet
• R-3: Joint length must be over 34 feet, and 95% must have lengths greater than 36 feet.

The API grade of casing denotes the steel properties of the casing. The grade has a letter, which designates the grade, and a number, which designates the minimum yield strength in thousands of psi.

Casing - liner

Liner

A liner is a string of casing that does not reach the surface. They are usually “hung” (attached to the intermediate casing using an arrangement of packers and slips) from the base of the intermediate casing and reach to the bottom of the hole. The major advantage of a liner is the cost of the string is reduced, as are running and cementing times. During the course of the well, if the liner has to be extended to the surface (making it another string of casing), the string attaching the liner to the surface is known as a “tie-back” string.

Casing - Production Casing

Production Casing

Production casing is usually the last full string of pipe set in a well. These strings are run to isolate producing formations and provide for selective production in multi-zone production areas. The size of production casing will depend on the expected production rate, the higher the barrel per day production rate, the larger the inside diameter of the pipe. Common sizes are between 3 and 7 inch (outside diameter).

Casing - Intermediate Casing

Intermediate Casing

Intermediate casing is set after surface casing, normally to seal off a problem formation. The size of intermediate casing, will depend on the size of the surface casing and the grade required to withstand the subsurface conditions. Normal sizes are between 9 5/8 and 13 3/8 inch (outside diameter).

Casing - Surface Casing

Surface Casing

The amount of surface casing used will depend on the depth of the unconsolidated formations. Surface casing is usually set in the first competent formation. Normal size for surface casing is between 20 inch and 13-3/8 inch (outside diameter). Since temperature, pressure and corrosive fluids tend to increase with depth, different grades of casing will be required to handle the different well conditions. 

Purposes of surface casing are to:

• protect fresh water formations

• seal off unconsolidated formations and lost circulation zones

• provide a place to install the B.O.P.'s

• protect “build” sections on deviated wells

• provide for a sufficient “leak-off” test to be conducted

Casing - Conductor Casing

Conductor Casing

Conductor pipe or drive pipe if it is hammer-driven to depth, is the first string of casing to be used. The setting depth can vary from 10 ft to around 300 ft. The normal size range for conductor pipe is from 16 to 36 inches (outside diameter). The conductor pipe must be large enough to allow the other casing strings to be run through it. Purposes of conductor pipe are to:

• raise the level of circulating fluid so that fluid returns are possible

• prevent washouts in the near surface, normally unconsolidated formations

Casing

Casing

Casing has several important functions during the drilling and completing of a well. It is used to prevent the borehole from caving in during the drilling of the well, to provide a means of controlling fluids encountered while drilling, to prevent contamination of fluids to be produced, and to protect or isolate certain formations during the course of a well. Casing is also one of the most expensive parts of a well, around 20% of the cost of a completed well.

Casing is usually divided into five basic types.

Swab And Surge Pressures

Swab And Surge Pressures

Both swab and surge pressures are caused by moving the drillstring axially, and can be calculated using a method similar for calculating annular pressure losses. The greatest difficulty is determining the fluid flow velocity in the annulus when the pipe is opened-ended, because the
distribution of flow between the drillstring and annulus cannot be determined by a simple method.
Two approaches have been proposed.

The first assumes that fluid levels in the annulus and drillstring remain equal at all times. Annular fluid velocity then becomes:


where: Va = Average velocity (ft/min)
Vp = Drillstring velocity (ft/min)
D = Borehole Diameter (inches)
d = Drillstring Outside Diameter (inches)
di = Drillstring Inside Diameter (inches)

The minus sign is in the equation because the drillstring velocity is in the opposite direction to the fluid velocity.

This average velocity equation remains valid even when hole geometry changes. This method is easy to apply and is in widespread use in the oilfield. Its basic premise, that fluid levels in the drillstring and annulus
remain equal, is rarely justified. Because of the greater restrictions to flow, caused by the bit nozzles and pipe bore, actual flow in the annulus will nearly always exceed that calculated by this method. Calculated swab and surge pressures are therefore usually too low.


An alternative procedure considers the drillstring and the annulus as a “UTube”, as shown in the following figure.
 It is clear that the sum of hydrostatic and frictional pressures in the pipe bore and through the bit should equal the sum of hydrostatic and frictional pressures in the annulus. Both sums represent the pressure prevailing immediately below the bit.
There is only one flow distribution that will fulfill this criterion, and it can
be found by trial and error through the use of the pressure loss equations.

Figure 1-3: Equal Level Displacement

When tripping out of the hole, it may be assumed that both drillstring and annulus are kept full of fluid. The required distribution of flow is that which gives equal frictional losses in the pipe bore and annulus. When tripping into the hole, the fluid level inside the drillstring can drop well below that in the annulus, if small bit nozzles are present. This effect is usually seen as a pit volume being higher than expected, string weight lower than expected, and a considerable volume being pumped before standpipe pressure builds up while breaking circulation.

When the fluid level in the drillstring is below that of the annulus, a greater hydrostatic pressure will exist in the annulus, and fluid will tend to flow from the annulus up the drillstring. In this case, calculating flow distribution by equating frictional losses gives a calculated annular flow and surge pressure slightly higher than actually exists. Because this error is small and conservative, and because at present there is no reliable way of measuring the fluid level within the pipe, the practice of calculating flow distribution by equating internal and external pressure losses is generally accepted.

If the pipe is closed, or contains a float sub, it is easy to calculate flow in the annulus, because all of the fluid displaced by the drillstring passes up the annulus.

Calculating the pressure drop in the annulus is complicated by the motion of the inner wall of the drillstring. This motion is in the opposite direction to the displaced fluid, so the pressure drop will be greater than that for the same flowrate in a stationary annulus . Equations describing the system can be formulated, but solutions are usually too complicated for wellsite use.
Figure
 

Bit Hydraulics And Optimization - Diamond Bit Flow Patterns

Diamond Bit Flow Patterns

There are two main flow patterns in diamond bits:

1. Cross Pad Flow System (feeder/collector system)

a) the fluid travels along the high pressure “primary fluid courses” (those which connect to the crowfoot), to a point where “low pressure collectors” draw the fluid across the diamond pad

b) this ensures that the diamonds towards the outside diameter are cleaned and cooled

c) The HSI should be between 1.5 and 2.5.

2. Radial Flow System

a) provides a “high pressure primary fluid course” for each diamond row

b) permits fluid to travel in front of, and behind each diamond pad to facilitate cuttings removal and cooling

c) maintains uniform horizontal fluid velocity by tapering fluid course depth as they approach the outside diameter

d) The HSI should be between 2.0 to 3.0.

Drill String Sticking Prevention

Stuck pipe

During drilling operations, a pipe is considered stuck if it cannot be freed from the hole without damaging the pipe, and without exceeding the drilling rig’s maximum allowed hook load. Pipe sticking can be classified under two categories: differential pressure pipe sticking and mechanical pipe sticking.
Mechanical causes for stuck pipe include:

Keyseating
Packoff from poor hole-cleaning
Shale swelling
Wellbore collapse
Plastic-flowing formation (i.e., salt)
Bridging
Preventing stuck pipe can require close monitoring of early warning signs, such as:

Increases in torque and drag
Excessive cuttings loading
Tight spots while tripping
Loss of circulation while drilling .

Bit Hydraulics And Optimization - Diamond Bit Hydraulics

Diamond Bit Hydraulics

The horizontal fluid velocity is the key element in diamond bit life and bit performance. It can be determined using:

The fluid courses assist this by directing the drilling fluid across the bit to cool the diamonds and to remove the cuttings.

 The diamond bit “Total Flow Area” consists of two components:

1. Fluid Course Area - is the area of all fluid courses on the bit. They are cast into the bit body.

2. Diamond Exposure Area - is the area between the bit face and formation, produced by the diamond exposure.

The desired TFA is calculated and designed into the bit by varying the diamond exposure, and the width and depth of the fluid courses. Another phenomenon which occurs with natural diamond bits is called hydraulic pump-off. The hydrodynamic pressure of the mud at the bit acts over the bit face area (between the cutting face of the bit and the formation) and tends to lift the bit off the bottom of the hole. For example, the pumpoff force on a 8-1/2 inch radial flow diamond bit (having a pressure drop of 900 psi) would be approximately 8600 pounds. It will require at least this much bit weight to keep the face of the bit in contact with the bottom of the hole.

Bit Hydraulics And Optimization - PDC Bit Hydraulics

PDC Bit Hydraulics

Since PDC bits are formation specific (best used in plastic formations), the formation characteristics will determine the hydraulic energy required. The drilling fluid will dictate the HSI, for water-based drilling fluids it will be between 2.5 and 4.5, while for oil-based drilling fluids it will be between 1.5 and 3.0.

The HSI, calculated at the jet nozzle orifices, will have several characteristics which will directly affect hydraulic energy:

1. the fluid velocity decreases rapidly once it leaves the nozzles
2. high vertical velocity and low horizontal velocities are achieved across the bit face
3. for higher volumes of fluid pumped, horizontal velocities will increase, but not necessarily HSI

The increased horizontal velocities provide better cuttings removal, better cooling, and possibly better drill rates.

Nozzle velocity is calculated in the same manner as with rollercone bits.

Bit Hydraulics And Optimization-Fixed Cutter Bit Hydraulics

Fixed Cutter Bit Hydraulics
The hydraulics for fixed cutter bits is based on the drilling fluids ability to remove cuttings beneath the cutters and to cool the bit. Fluid volume is critical to PDC bit performance. Fluid volume and fluid velocity is critical to diamond bit performance.

The major components of fixed cutter bit hydraulics are:

1. flow rate - Q (gal/min) and V (ft/min)
2. drilling fluid characteristics - MD (lb/gal), YP (lbs/100ft2) and PV (cps)
3. pressure loss - across the bit face (diamond bit) or through the jet nozzles (PDC bit)
4. the Total Flow Area (TFA) - instead of nozzle sizes

A very important parameter in fixed cutter bits is “Hydraulic Power Per Square Inch” or HSI. It is calculated using Hhp (hydraulic horsepower):

where: Hhp = Hydraulic Horsepower
A = Bit Area (square inches)*
* If the area of the bit is not given, it can be calculated using:

where: d = bit diameter (inches)
The hydraulic horsepower equation is the same (Pb x Q/1714), however in fixed cutter bits, resistance to fluid flow is created by the diamonds, nozzles, flow area restrictions, cuttings and the uneven hole pattern. Pressure losses at the bit are calculated using:

Bit Hydraulics And Optimization - Hydraulic Impact Force

Hydraulic Impact Force
Hydraulic (Jet) Impact Force is based on the theory that cuttings are best removed from beneath the bit when the force of the fluid leaving the jet nozzles and striking the bottom of the hole is the greatest. Impact Force is determined by:




where: MD = Mud Density (lb/gal)
Q = Flow Rate (gal/min)
Vn = Nozzle Velocity (ft/sec)
As can be seen, Impact Force depends on maximizing flow rate and nozzle velocity rather than pressure. Therefore, higher flow rates are required. The emphasis is on a large volume of fluid impacting with moderate force, rather than a small volume impacting at a high pressure.
This condition is optimized when circulating rates and bit nozzle sizes are chosen which will cause 48% of the pump pressure to be used to force fluid through the jet nozzles.

Bit Hydraulics And Optimization - Hydraulic Horsepower

Hydraulic Horsepower

Hydraulic horsepower is based on the theory that cuttings are best removed from beneath the bit by delivering the most power to the bottom of the hole. 

The amount of pressure lost at the bit, or bit pressure drop, is essential in determining the hydraulic horsepower. Bit pressure drop is determined by:

where: MD = Mud Density (lb/gal)

Vn = Nozzle Velocity (ft/sec)

From the bit pressure loss, hydraulic horsepower can be calculated:

To optimize Bottom Hole Cleaning and Bit Hydraulic Horsepower, it is necessary to select a circulation rate and nozzle sizes which will cause 65% of the pump pressure to be expended forcing the fluid through the jet nozzles of the bit.   

Bit Hydraulics And Optimization - Bottom Hole Horsepower

Bottom Hole Horsepower

Determination of the amount of Bottom Hole Cleaning necessary to maximize the drill rate is based upon:

1. Hydraulic (Jet) Impact Force

2. Hydraulic Horsepower

Maximizing Hpb involves minimizing Hpc, or in other words, the lowest flow rate and the highest pump pressure will result in the highest Hpb. However, the “lowest flow rate” will usually result in inadequate bottom hole cleaning. To compensate for this, bottom hole pressure can be increased by using smaller jet nozzles.

Bit Hydraulics And Optimization - Surface Horsepower

Bit Hydraulics And Optimization- Surface Horsepower

In order to maximize a hydraulics program, all aspects concerning drilling fluids and the associated equipment must be considered. The first component in any hydraulic design is the surface equipment and the hydraulic horsepower available from them. There are two limiting factors on the surface hydraulic horsepower.

The first is the flow rate range. As discussed earlier, the flow pattern in the annulus should be laminar, therefore the upper limit for the flow rate is a Reynolds Number of 2000. The highest velocity in the annulus will be around the collars, and this velocity can be determined by calculating the “critical velocity” over that section. In addition, running the pumps at that upper range is not always advisable because there will be more wear and tear on the pumps and much more fuel consumption.

The lower limit is a range where there is sufficient hole cleaning. This is determined by using the velocity around the drillpipe and the largest annular section (normally the upper hole section or drillpipe/riser section). 

A normal range is around 50 ft/min.

The second factor is the operating pressure of the mud pumps. Most mud pumps can produce the required pressure with little problem. However, because of the various components associated with the surface system (standpipe, rotary hose, pulsation dampener, etc.) the maximum surface pressure is usually limited to some value less than the maximum rated pump pressure.

The available “surface horsepower” is then determined by:

where: Hps = Surface Horsepower

P = Pump Pressure (psi)

Q = Pump Flow Rate (gal/min)

Once the surface horsepower has been determined, the horsepower distributions can be made:

where: Hpc = Circulation Horsepower

Hpb = Bit Horsepower

Bit Hydraulics And Optimization- Jet Nozzles

Bit Hydraulics And Optimization
Jet Nozzles

Jet Nozzles were introduced into the oilfield in 1948. These were necessary to increase bottom hole cleaning in deep wells. Prior to jet nozzles, the fluid course in bits was a hole bored into the center of the bit and the drilling fluid went from the drillstring directly into the annulus.
These “conventional water courses” did not have the power necessary to lift the cuttings and assist in the drilling process.

Both roller cone bits and PDC bits have recesses to install different size jet nozzles in order to obtain proper hydraulics. Most roller cone bits use three or four jet nozzles, while PDC bits usually contain six to nine. The flow area of all jets must be determined separately, then added together. For example, suppose four size 9 jets were being used:



There are four jets so the total flow area is 0.0621 x 4 or 0.2486 in2. Jet nozzles increase the speed of the drilling leaving the bit to around 225 ft/sec, and on many occasions the velocity is much greater. Because nozzle velocity is so important in hydraulic optimization, it should be calculated when the jets are installed in a bit. The formula is:



As mentioned in the previous section, the rate of penetration can be improved if the cuttings are removed from beneath the bit. In soft formations, the hole is generated by the jetting action of the drilling fluid, and the drill rate is limited by connection time, undesirable deviations, and the loading of the annulus with cuttings. In hard formations, the drill rate should be proportional to the weight-on-bit, if hole cleaning is adequate.

Cuttings Slip Velocity

Cuttings Slip Velocity

A cutting, traveling up the annulus, experiences a positive upward force due to the drilling fluid velocity, density and viscosity, and a negative downward force due to gravity. The rate at which a cutting falls is known as its “slip velocity”.

Several studies have enabled the following generalizations to be made:

1. The most important factors controlling adequate cuttings transport are annular velocity and rheological properties

2. Annular velocities of 50 ft/min provide adequate cuttings transport in typical muds

3. Cuttings transport efficiency increases as fluid velocity increases

4. The slippage of cuttings as they are transported induces shear thinning of the mud around the cutting reducing the expected transport efficiency

5. Cutting size and mud density have a moderate influence on cuttings transport

6. Hole size, string rpm, and drill rate have slight effects on cuttings transport.

Those who have observed a solids tracer emerging over the shale shaker will realize the large spread of “cuttings” that occurs. Therefore, any calculated estimation of slip velocity will only be an approximation. The reason for this “spread” of solids is the particles ability to be carried by the drilling fluid. It is a function of its position in the mud stream and the size of the particle. Cuttings will travel up the annulus more efficiently if they travel flat and horizontally. If the cutting turns on its edge, it will slip more easily. Smaller cuttings are more prone to do this. Rotation of the drillpipe will result in a helical motion of the fluid, which will aid transport for those

cuttings nearest the pipe.

The rheological properties of the drilling fluid will affect cuttings transport, in as much as they affect the flow profile. Lowering the “n” value or an increases in the YP/PV ratio will generally flatten the flow profile and increase carrying capacity.

The slip velocity of a cutting in turbulent flow may be estimated using:

where: Vs = Slip Velocity (ft/min)

dp = Particle Diameter (inches)

pp = Particle density (lb/gal)

MD = Mud Density (lb/gal)

CD = Drag Coefficient

For these calculations, the particle density is found by multiplying the cuttings density (gm/cc) by the density of fresh water (8.34). The drag coefficient is the frictional drag between the fluid and the particle.

In turbulent flow, the drag coefficient is 1.5.

In laminar flow, the equivalent viscosity (m) will effect the slip velocity. In this case the slip velocity is

:

Equivalent viscosity is calculated as mentioned earlier.

Cuttings Transport

Cuttings Transport

One of the primary functions of a drilling fluid is to bring the drilled cuttings to the surface. Inadequate hole cleaning can lead to a number of problems, including hole fill, packing off, stuck pipe, and excessive hydrostatic pressure. The ability of a drilling fluid to lift cuttings is affected by many factors, and there is no universally accepted theory which can account for all observed phenomena. Some of the parameters which affect cuttings transport are the fluids density and viscosity, annular size and eccentricity, annular velocity and flow regime, pipe rotation, cuttings density, and the size and shape of the cuttings.

If the cuttings are of irregular shape (and most are) they are subjected to a torque caused by the shearing of the mud. If the drillpipe is rotating, a centrifugal effect causes the cuttings to move towards the outer wall of the annulus. The process is further complicated because the viscosity of non- Newtonian fluids varies according to the shear rate, and therefore the velocity of the cutting changes with radial position. Finally, transport rates are strongly dependent on cutting size and shape, which as stated above, are both irregular and variable.

The only practical way to estimate the slip velocity (or relative sinking velocity) of cuttings, is to develop empirical correlations based on experimental data. Even with this approach, there is a wide disparity in the results obtained by different authors.

Reynolds Number and Critical Velocity

Reynolds Number and Critical Velocity

The Reynolds Number, used in the annular Power Law Model calculations is calculated using equivalent viscosity


:

Reynolds Number is then:




The fluid velocity that will produce the critical Reynolds Number for given fluid properties and pipe configuration is found using:




where: ReL = Laminar/Transitional Reynolds Number
(3470-1370n).