COMPUTALOG DRILLING SERVICES

I Operations Manual OPDD _140_revA_0304

Computalog Drilling Services

!6172. \fVes: HS"CY Roac HcGsto:: Texas 77060 ie!e:Jnone: 28!26D.570C Facs,nrie: 281.260.5780

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Precision Drilling

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Overview of Computalog

CHAPTER1 Directional Drilling

Introduction Directional Drilling Terminolo~~\pplications of Directional Drilling Directional Drilling Limits

CHAPTER2 Methods of Deflecting a Wellbore

Bottomhole ~\ssemblies Building ~\ssemblies Dropping ~\ssemblies Holding ~\ssemblies Jetting Special BH.:\'s Stabilization Rotating Blade Type Continue ....

Integral Blade Stabilizer \Velded Blade Stabilizers Shrunk on Sleeve Stabilizers Replaceable Slee,c-Type Stabilizer Common BfL\ Problems \Xib.ipstock Dm,nhole :.\Iotors w/ Bent Sub Steerable ~\ssembh

CHAPTER3 Downhole Mud Motors

l\Iotor Selection Components Dump Sub ~\ssembly Power Section Drive _\ssembh

~\djustable ~\ssembly Sealed or l\Iud Lubricated Bearin

Planning T earn Planning Geosteering

CHAPTER 7 Magnetics

Magnetic Fields 1\Iagnetic Interference Drill String :;\lagnetic Interference

~Iinimizing Errors External :\lagnetic Interference Directional Sensor Package Spacing The Earth's Gravitational Field ~\pphcations of Magnetics & GravitY

CHAPTERS Survey Equipment, Selection & Accuracy

:\Iagnetic Single Shot & 1\Iultishots ~Iagnetic 1\Iultishot Surve:- Instrument Gnoscopes Evolution of Gnoscopes Used in Surve,-ing Oil Wells Survey ~\ccuracy & Qualin- Control Gno Errors 1\Ieasurements \'\bile Dr:ilhng (1\~D) Directional Sensor Package

CHAPTER9 Operational Considerations

CHAPTER 10 The Problem of Deviation & Doglegging Rotary Boreholes

Table 1: Surve,- Results from Seminole Theories of Causes of Deviated Field Holes Categorizing Crooked Holes

CHAPTER11 Planning an U nderbalanced Hz Well

Introduction Wby Drill Underbalanced Limitations Directional Planning Issues Operational Issues Equipment & Dr:ilhng Problems

Downhole ~Iotor Tests Cnder Two Phase Flow \\bat this ~leans to a Directional Driller Conclusions & Recommendations

CHAPTER 12 Underbalanced Drilling To Be Developed

Formation Damage UBD or CPD Modeling UBD Equipment Gas Supply ~\ltematives Corrosion Issues

ALGERIA COURSE

OVERVIEW OF COMPUTALOG DRILLING SERVICES

Computalog is a Canadian company wholly owned by Precision Drilling. Computalog was started in 1972 as a small perforating company under the name Perfco. Perfco grew into a small 'WTieline company and with Gearhart Industries in 197 -t- formed Computalog Services. They continued to grow providing cased and open logging services through a newly de\'eloped direct digital logging system. In 1979 Gearhart Industries was developing measurement while drilling (.lvf\\D) systems in the United States. In 1980 the name was changed to Computalog Gearhart Ltd. and became a publicly traded company \v~th stations in the US and Canada. In 1983 United Directional Drilling and Trigon Oil well Surveys were purchased to provide a direct supplier to the oilfield of the latest l\1\\D technology to the Canadian oil industry. Computalog introduced the first J\.fWD gamm.a ray tool into Canada in 198-t-.

In 1987 Computalog acquired several more companies including Maxi-Torque, a manufacturer of downhole positive displacement motors used primarily for directional drilling operations. Also Computalog continued to expand its presence in many international areas including China, Africa, Costa Rica and the Middle East.

In 1989 the name was changed to Computalog Ltd. and developed its own J\.1\\D system. The \VTieline group was also expanding and developing new technology rapidly. In 1997, Computalog entered into a joint venture with Geoservices S.A. of France, the worlds largest supplier of electromagnetic M\\D technology. The partnership was called United GeoCom Drilling Services. United GeoCom Drilling Services became the third largest directional drilling company in Canada. UGC has continued to grow and is now one of the largest directional companies in Canada \\~th the most experience at pro\'iding underbalanced drilling sen,ices to the oil industn'.

In 1999, Precision Drilling purchased Computalog and joined it with several other sen'ice supply companies to become a very unified and growth oriented company. \\'e have a significantly improved research and development budget and are now poised to develop new and improved technology: 1) new generation l\1\\D with a full suite logging while drilling tools, 2) rotary steerable directional system and 3) improved multilateral window and tie-back systems for horizontal wells to name a few. \\' e are also making improvements in the \VTieline division as well.

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Chapter

DIRECTIONAL DRILLING

Introduction

In the early days of drilling, no one worried about hole deviation. The whole objective was to get the well drilled down, completed and producing as quickly as possible. Many drilling personnel assumed the \.Veils were straight - others simply did not care.

Subsequently, wells were deliberately drilled in some unknown direction. This began as a remedial operation to solve a d1illing problem - usually a fish or junk left in the hole. Today, '.Ni.th the advent of tighter legal spacing requirements, better reservoir engineering modelling and drilling of multiple wells from a single surface location, it has become very important to both control the \.vellbore position during drilling and to relate the position of existing wellbores to lease boundaries, other wells, etc.

The development of the skills and equipment necessary to direct these wellbores is the science of directional drilling. Directional Drilling is tl1e science of directing a wellbore along a predetermined path called a trajectory to intersect a pre,iously designated sub-surface target. Implicit in this definition is the fact that both the direction and the dev-iation from vertical are controlled bY the directional driller from tl1e surface.

Directional Drilling Terminology

A short glossary of the more frequently used terms for Directional Drilling is included here and is intended only as an aid in understanding directional drilling terminology and is neither a definitive ,,ork in the field nor by any means complete. Some of the more important and commonly used terms are:

Target

The target, or objective, is the theoretical, subsurface point or points at which the wellbore is aimed. In the majority of cases it will be defined by someone other than the directional driller. Usually this will be a geologist, a reservoir engineer or a production engineer. They '.NW often define the target in terms of a physical limitation - i.e. a circle witl1 a specified radius centred about a specified subsurface point. If multiple zones are to be penetrated, the multiple targets should be selected so that the planned pattern is reasonable and can be achieved '.Ni.thout excessive drilling problems.

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Some care should be taken \vith target definition. Any target can be reached -given enough time, money and effort but the economics of drilling dictate the use of as large a target as possible. Each of the various targets is discussed below:

1. Circular

~\ horizontal circle of given radius about a fn;:ed subsurface point. ,., Bounded

~\ circular, square or rectangular shape with at least one side fn;:ed by a physical constraint e.g. a fault, a formation change (salt dome), legal boundan- etc.

3. Angle at Depth

Targets may be defined as an angle limitation at depth- e. g . .2 or so from projected trajectory.

\\ben targets are defmed the directional driller must also know the true vertical depth at \vhich the target applies. In some cases this depth may not be a\ailable '-V'ithin sewral hundred meters and could be specified as the wellbore intercept of a given formation top. This top of target would almost certainly preclude the use of Build and Hold wells and require use of "S" shaped wellbores.

Target Displacement

Target displacement is defmed as the horizontal distance from the surface location to centre of the target in a straight line. This is also the directional summation of the departure (the due East or West displacement) and the latitude (the due North or South displacement).

The target bearings are a measure of the direction in degrees, minutes and seconds (or decimals) and typically expressed with reference to well centre.

True Vertical Depth

True Vertical Depth (TVD) is the depth of the wellbore at any point measured in a vertical plane and normally referenced from the horizontal plane of the kelly bushing of the drilling rig.

Kick Off Point

This is the point at which the flrst deflection tool is utilized and the increase in angle starts. The selection of both the kick off point and build up rate depend on many factors including the formation(s), wellbore trajectory, the casing program, the mud program, the required horizontal displacement, maximum allowable dogleg and inclination. This Kick Off Point (KOP) is carefully selected so the

maximwn angle is within economical limits. Fewer problems are faced when the angle of the hole is between 30 and 55. The deeper the KOP is, the more angle it '.V-ill be necessary to build, possibly at a more aggressi\'e rate of build. The KOP should be at such a depth "\vhere the maximwn angle to build up would be around 40"; the preferred minimwn is 15".

In practice the well trajectory may be calculated for several choices of KOP and build up rates and the results compared. The optimwn choice is that which gives a safe clearance from all existing wells, keeps the maximum inclination within the desired limits, avoids unnecessarily high dogleg severity's and is the best design from a cost point of view.

Build Rate

The change in inclination per measured length drilled (typically 0 /100' or 0 /30 m). The build rate is achieved through the use of a deflection tool (positive displacement motor with a built in adjustable housing or purposefully designed stabilized bottomhole assembly).

Build Up Section

This is the part of the hole where the vertical angle is increased at a certain rate, depending on the formations and drilling assembly used. During the Build Up the drift angle and direction are constantly checked in order to see whether a course correction or change in build rate is required. This part of the hole is the most critical to assure the desired wellpath is maintained and the flnal target is reached.

Tangent

This section, also called the Hold Section, is a straight portion of the hole drilled with the maximwn angle required to reach the target. Subtle course changes may be made in this section.

Many extended reach drilling projects have been successfully completed at inclinations up to 80, exposing much more reservoir surface area and reaching multiple targets. However, inclination angles over 65 may result in excessive torque and drag on the drill string and present hole cleaning, logging, casing, cementing and production problems. These problems can all be overcome with today's technology, but should be avoided whenever there is an economic alternative.

Experience over the years has been that directional control problems are aggravated when the tangent inclination is less than 15. This is because there is more of a tendencY for bit walk to occur, i.e., change in azimuth, so more time is spent keeping the ~ell on course. To summarise, most run-of-the-mill directional wells are still planned with inclinations in the range 15- 60 whenever possible.

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Drop Section

In S-type holes, the drop section is where the drift angle is dropped dm.vn to a lower inclination or in some cases vertical at a defmed rate. Once this is accomplished the well is rotary drilled to TD \vith surveys taken e\ery 50m (150').

The optimum drop rate is between 1 o_ 2 1fz degree per 30m and is selected mainlY with regard to the ease of rllllning casing and the a\oidance of completion and production problems.

Course Length

This course length is the actual distance drilled by the well bore from one point to the next as measured. The summation of all the course lengths is I\Ieasured Depth of the \veil. The term is usually used as a distance reference beru:een survey pomts.

The Horizontal Projection (Plan View)

On many well plans, the horizontal projection is just a straight line drawn from the well centre or slot to the target. On multi-well platforms it is sometimes necessar; to start the well off in a different direction to avoid other wells. Once clear of these, the well is turned to aim at the target. The path of the drilled well is plotted on the horizontal projection by plotting total North/South co-ordinates (Northings) versus total East/\\'est co-ordinates (Eastings). These co-ordinates are calculated from surveys.

Vertical Section

The Vertical Section of a well is dependent upon the bearing or azimuth of interest. It is the horizontal displacement of the well path projected at 90 to the desired bearing.

Lead Angle

Since roller cone bits used with rotary assemblies tend to "walk to the right", the wells were generally kicked off in a direction several degrees to the left of the target direction. In extreme cases the lead angles could be as large as 40.

The greatly increased use of steerable motors, changes in conventional rock bit design and the \videspread use of PDC bits for rotary drilling have drastically reduced the need for wells to be given a "lead angle". Most wells todaY are deliberately kicked off \vith no lead angle, i.e., in the target direction.

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Applications of Directional Drilling

Multiple Wells From Offshore Structure

One of toda:)s more common applications of directional drilling techniques is in offshore drilling. Many oil and gas deposits are situated beyond the reach of land based rigs. To drill a large number of \'ertical wells from individual platforms is impractical and would be uneconomical. The conventional approach for a large oilfield has been to install a fixed platform on the seabed, from which as many as

si~tY directional wells rna\' be drilled. The bottomhole locations of these wells can 0

be carefully spaced for optimum recm'ery. This type of development greatly improves the economic feasibility of the expensive offshore industry by reducing the number of platforms required and simplifying the gathering system.

In a conventional development, the wells cannot be drilled until the platform has been constructed and installed in position. This may mean a delay of 2-S years before production can begin. This delay can be considerably reduced by pre-drilling some of the wells through a subsea template while the platform is being constructed. These wells are directionally drilled from an offshore rig, usually a semi-submersible, and tied back to the platform once it has been installed.

Relief Wells

Directional techniques are used to drill relief wells in order to "kill" blowout wells. The relief well is deviated to pass as close as possible in the reservoir to the uncontrolled well: it is not generally targeted to hit the out of control well as costs to do this would be prohibitive. Heavy mud is pumped into the resen'oir to overcome the pressure and bring the wild well under control.

Controlling Vertical Wells

Directional techniques are used to "straighten crooked holes". In other words, when deviation occurs in a well which is supposed to be vertical, various techniques are used to bring the well back to vertical. This was one of the earliest applications of directional drilling.

Sidetracking

Sidetracking out of an eX1stmg wellbore is another application of directional drilling. This sidetracking may be done to bypass an obstruction (a "fish") in the original wellbore or to explore the extent of the producing zone in a certain sector of a field.

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Inaccessible Locations

Directional wells are often drilled because the surface location directk abm'e the rese1Toir is inaccessible, either because of natural or man-made obstacles. Examples include reservoirs under cities, mountains, lakes, etc.

Other Applications

Directional wells are also drilled to avoid drilling a vertical well through a steeply inclined fault plane, which could slip and shear the casing.

Directional \\'ells ma;., also be used to 0\'ercome the problems of salt dome drilling. Instead of drilling through the salt, the well is drilled at one side of the dome and is then de,""iated around and underneath the 0\'erhanging cap.

Directional wells may also be used where a reservoir lies offshore but quite close to land, the most economical ,,ay to exploit the reservoir may be to drill directional wells from a land rig on the coast.

Reservoir Optimization

Horizontal drilling is the fastest growing branch of directional drilling. Horizontal wells allow increased reservoir penetration, especially in thinner reservoirs, allow increased exposure of the pay zone and allow higher production rates at equivalent drawdowns. Numerous specific applications for horizontal drilling are being developed with major ad"\'ances occurring in the tools and techniques used.

Multilateral Wells

Within the science of horizontal drilling, multilateral hole drilling is rapidly becoming a common occurrence. \\.ells are drilled horizontally to total depth and laterals drilled from them in various directions. These laterals remain essentially horizontal and are directionally controlled to ensure maxinmm pay zone exposure.

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Sidetracking

Inaccessible locar.i:ons

1\!ultiple wells from a single \\ell

l" nder lakes

~..AJV'JJ\.A ... A.A.A./ '""./-.J*_.Z-.d~J"""~""""~

'-'Y'_~'"!..~"--'

Salt dome drilling

Fault controlling

Offshore multi-well drilling

Multiple sands trom a single wdlbore

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Drilling relief wells HorizontJl "'-~ells

Speciality Applications

In addition to exploration for oil and gas, controlled directional drilling practices are used in other industries such as construction and mining. The follm:1.:ing examples are applications in common use:

Conduit holes - Holes drilled to accommodate pipelines, cables or other transmission mediums. These holes are generally drilled to traverse obstacles in a proposed right of way which present problems to conventional trenching methods such as:

- Ri1.er crossings - Steep or unstable terrain presenting backfill and future erosion problems - Shore approaches - Emnonmentall1. sensitive areas.

Storage Ca,erns

Solution 1\fining- Extraction of water-soluble minerals (e.g. salt, potash) can be attained through solution mining technologies. In this practice, ''paired" wells are drilled to predetermined targets and water is circulated through the holes until communication is established. \X'ater is then forced down one hole and allowed to exit through the other carrying \vith it the mineral in solution. At surface the minerals are removed through various methods and the \Vater re-circulated in a continuous procedure.

Grout Holes - Proper placement and control of grout holes (to stabilize unconsolidated formations or isolate water-bearing formations) ~.,vill result in reduced overall costs and greater technical efficiencies for the procedure.

Evacuation Holes - Methane and water drainage holes have been common in the mining industry for years. Similar technologies are now being employed in the environmental area for in-site evacuation of toxic contaminants left in

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industrial and waste disposal sites.

Directional Drilling Limits

Any drilling limit described in a textbook written today would be simply broken tomorrow by some operator. \v'e have drilled horizontal wells with laterals m'er 6,1 OOm long; extended reach wells with over 1 O,OOOm of horizontal reach (horizontal to \'ertical ratio of 6 or 7 to 1); multi-lateral horizontal wells '.v:ith 10 legs; purposefully turned horizontal wells 180 in bearing; drilled 27 wells off a single land based pad location; re-entered just about every wellbore configuration to drill to a new target and are now drilling stacked well pairs '.Vi.thin 3m (10') of each other. Coiled tubing drilled wells are also setting ne\v records 'Wi.th lateral sections in excess of 1,100m. Just about anything can be drilled prm,ided you have the fmancial support. It is better to know the potential equipment or wellbore limitations. The following is a list of some of the factors considered when planning a directional \veil that will be further discussed in a later section:

1.) Through experience many operators have established their own maximum inclination and/ or dogleg severity limits to minimize rod and casing wear.

2.) Open-hole and cased hole logging equipment have linuts on dogleg se\'erity the tools can safely pass through that depends upon the tool OD, hole OD and tool length.

3.) It may be impossible to get sufficient weight on bit (\\'OB) to drill the well depending upon factors such as drag, drill string assembly design, mud type and hole geometry to name a few.

4-.) Kn seat and differential sticking potentials.

5.) Maximum dogleg directional equipment can be rotated or slid through (bending stresses).

6.) \\'ellbore stability (tectonic conditions, sloughing, boulders)

7.) The ability to steer the BHA along the required course (reactive torque).

8.) Ability for equipment to build inclination at the required rates

As directional drilling technologies continue to develop, new applications 'Wi.ll emerge. Although oil and gas drilling applications will continue to dominate the future of the directional industry, environmental and econon1ic considerations will force other industries to consider directional drilling alternatives to conventional technologies.

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Chapter

METHODS OF DEFLECTING A WELLBORE There are several methods of deflecting a 'vellbore. BY deflecting '-'Ve mean changing the inclination and/ or direction of a wellbore. The most common methods used todaY are:

1. Bottomhole ~\ssemblies

') J . - etung

3. \\bipstocks

4. Downhole Motors -most common

Bottomhole assemblies are the least expensi,~e method of deflecting a well and should be used whenever possible. Cnfortunately, the exact response of a bottomhole assembly is very difficult to predict and, left or right hand walk is almost impossible to control. \\'hen refinements of the wellbore course are necessatT usually the latter method is used.

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Bottomhole Assemblies

Before the invention of measurement while drilling (1\1\\D) tools and steerable motors, rotary bottomhole assemblies (BHA) were used to deflect wellbore. ~\ bottomhole assembly is the arrangement of the bit, stabilizer, reamers, drill collars, subs and special tools used at the bottom of the drill string. Anything that is run in the hole to drill, ream or circulate is a bottomhole assembly. The simplest assembly is a bit, collars and drill pipe and is often termed a slick assembly. The use of this assembly in directional drilling is very limited and usually confmed to the \~ertical section of the hole where deviation is not a problem.

In order to understand why an assembly \Vill deviate a hole, let's consider the slick assembly which is the simplest and easiest to understand. The deYiation tendency in this assembly is a result of the flexibility of the drill collars and the forces acting on the assembly causing the collars to bend. Even though drill collars seem to be very rigid, they will bend enough to cause deviation.

The point at which the collars contact the low side of the hole is called the tangency point. The distance L from the bit to the tangency point is dependent upon collar size, hole size, applied bit weight, hole inclination, and hole curvature. Generally, the distance Lis less than SOm (150 feet).

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~\bm'e the tangency point of the slick assembly, the remainder of the drill string generally has no effect on dev'iation. As weight is applied to the bit, the tangency point vvill move closer to the bit (Figure 4-1).

Because of the bending of the drill collars, the resultant force applied to the formation is not in the direction of the hole axis but is in the direction of the drill collar axis. As bit weight is applied, the tangency point moves toward the bit increasing the angle. It can readily be seen that an increase in bit weight leads to an increase in dev':iation tendencY.

..

Figure +- 1 Effect of increased bit weight

Unfortunately, the direction of the resultant force is not the only force involved. The resultant force can be broken up into its components. The primary force would be the drilling force in line with the axis of the borehole. The bit side force is caused by the bending of the collars and is perpendicular to the axis of the borehole. The force due to gravity (acting on the unsupported section of drill collars) is in the opposite direction and counteracts the side force. The net deviation force is then equal to the summation of the bit side force and the force due to gravity. If the force due to gra-v':ity is greater than the bit side force the angle will drop.

The dev':iation tendency can be controlled by changing the bit weight. Increasing the bit weight will lower the tangency point increasing the angle. Since resultant force is proportional to the sine of angle, an increase in bit weight increases the bit side force and ultimately the deviation tendency. Of course, a decrease in bit weight will decrease the deviation tendency.

Another factor affecting deviation tendency is the stiffness of the drill collars. Stiffer collars will bend less, which increases the height to the tangency point. If

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the tangency point moves up the hole, then the de\'"i.ation tendency will be reduced. The relative stiffness of a drill collar is proportional to the collar radius to the fourth power.

Relative Stiffness Coefficient = E X I

E = Young's Modulus I = Moment of Inertia

As an example, assume the relatiw stiffness of a 6" drill collar is one and the ID of all drill collars is 2 inches. An 9" and 11" collar would be five and eleven times stiffer respectively (Table 4-1).

Table 4-1 Relative Stiffness of Drill Collars

Drill Collar Diameter Relative Stiffness Inches (mm)

11 (279) 11.4 9 (229) 5.1 7 (178) 1.9 6 (152) 1.0

4 314 (121) 0.4

Therefore, small diameter drill collars \VW enhance the deviation tendency. Table 4-1 shows the relative stiffness of \-arious drill collars when the stiffness of a 6" bY 2" ID drill collar is assumed to be one.

The addition of a stabilizer above the bit significantly affects the deviation tendency of a bottomhole assemblY. The stabilizer acts as a fulcnun around which

. .

the unsupported section of the bottomhole assembly reacts. The addition of the moment arm between the bit and stabilizer increases the bit side force. In fact, the single stabilizer assembly is a very strong building assembly.

The addition of multiple stabilizers to an assembly makes the determination of side forces at the bit much more complicated. The analysis of these types of bottomhole assemblies is best suited for a computer and is beyond the scope of this manual.

Assuming the formation is uniform and the bit can drill in any direction, the bottomhole assemblY would drill in the direction of the vector sum of the forces at the bit. Unfortunately, the bit side-cutting and forward-cutting ability are not

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equal. Also, the anisotropic failure of the rock can cause a deviation in a direction other than the vector sum of the forces at the bit.

The side cutting abilit:~ of a bit is proportional to the side force exerted at the bit. L"nder static conditions, the side force on the bit can be calculated using a computer program. \\ben the entire bottomhole assembly is considered, it can also be shown the stabilizers in the assemblY exert a side force. The stabilizers have a side-cutting abilit:~ too. One would think the dev"l.ation tendency could then be calculated. Unfortunately, the side forces vvill. change under dynamic conditions. Both the bit and the stabilizers cut sideways reducing the side force on each until an equilibrium is reached.

L'nder dynamic conditions, the relative side-cutting of the bit and stabilizers becomes complicated which, in turn, makes the deviation tendency very difficult to calculate. The relationship between the bit and stabilizer side-cutting is dependent upon the t:"Pe of bit, t:"Pe of stabilizer, penetration rate, rotary speed, lithology, hole size, and bottomhole assembly t:1Je.

' ,.

"

Figure 4-2 Stabilizer Forces

The side-cutting abilit:~ of soft formation bits is generally considered better than for hard formation bits. Diamond bits have a greater side-cutting abilit:~ because they are designed vvith more of a cutting structure along the lateral face of the bit.

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The second factor affecting the de,~iation tendency is the anisotropic failure characteristics of the formation. In isotropic formations, equal chip Yolumes are formed on each side of the bit tooth and the bit will drill straight ahead (Figure 4 -3).

Figure 4-3 Illustration of Isotropic and Anisotropic Formations

But formations are not isotropic because the rock contains bedding planes. Also, the relati\~e hardness of the formation changes with vertical depth. In an anisotropic formation, relatively large chip ,~olumes are formed on one side of the bit tooth causing the bit to deviate (Figure 4-3).

The magnitude and direction of the formation deviation tendency \Vill depend upon bed dip. Generally, the bit "\\rill walk up dip when beds are dipping 0 to 45 and down dip when beds are dipping 65 to 90. Bed dips between 45 and 65 can cause either an up dip or down dip walk. Bed strike can cause the bit to walk left or right.

There are three basic types of assemblies used in directional drilling, they are:

1.) Building Assemblies,

2.) Dropping Assemblies

3.) Holding Assemblies

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A building assembly is intended to increase hole inclination; a dropping assembly is intended to decrease hole inclination; and a holding assembly is intended to maintain hole inclination. It should be noted that a building assembly might not ahvays build angle. Formation tendencies may cause the assembly to drop or hold angle. The building assembly is intended to build angle. The same is true for the dropping and holding assemblies.

Building Assemblies

As previously stated, the building assembly uses a stabilizer acting as a fulcrum to apply side forces to the bit. The magnitude of that force is a fw:1ction of the distance from the bit to the tangency point. An increase in bit weight and/ or decrease in drill collar stiffness ,-vill increase the side force at the bit increasing the rate of build.

The strongest building assembly consists of one stabilizer placed 3 to 6 feet above the bit face with drill collars and drill pipe above the stabilizer. This assembly will build under the majority of conditions. Of course, the rate of build will be controlled by formation tendencies, bit and stabilizer types, lithology, bit weights, drill collar stiffness, drill string rpm's, penetration rate, and hole geometry.

LOW

Figure -+--+ Building Assemblies

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.4,nother strong to moderate building assembly consists of a bottomhole stabilizer placed 3 to 6 feet from the bit face, 60 feet of drill collars, stabilizer, collars, and drill pipe. This is the most common assembly used to build angle. The second stabilizer tends to dampen the building tendencY. This assemblY can be used

. .

when the previous assembly builds at an excessi\Te rate. Other building assemblies can be seen in Figure 4-4.

Dropping Assemblies

A dropping assembly is sometimes referred to as a pendulum assembly. In this assembly, a stabilizer is placed at 30, 45, or 60 feet from the bit. The stabilizer produces a plumb bob or pendulum effect; hence the name pendulum assembly. The purpose of the stabilizer is to prevent the collar from touching the wall of the hole causing a tangency point the bit and stabilizer.

An increase in the length of the bottomhole assembly (the length below the tangency point) results in an increase in the weight. Since the force is determined by that weight, the force is also increased exceeding the force due to bending. The net result is a side force on the bit causing the hole to drop angle.

Additions of bit weight \\W decrease the dropping tendency of this assembly because it increases the force due to bending. Should enough bit weight be applied to the assembly to cause the collars to contact the borehole wall (between the stabilizer and the bit), the assembly will act as a slick assembly. Only the section of the assembly below the tangency point affects the bit side force.

If an increase in dropping tendency is required, larger diameter or denser collars should be used below the stabilizer. Tlus increases the weight of the assembly, wruch results in an increase in dropping tendency. As an example, suppose a dropping assembly with 7" (178mm) drill collars was being used in a 1~ 1 '4" (311mm) hole. By substituting 9" (229mm) collars for the 7" collars, an increase in dropping tendency can be acrunTed.

Dropping assemblies will have a higher rate of drop as hole inclination increases. The force wruch causes the dropping tendency is calculated using the following formula:

F = 0.5 X W X Sin (I)

\"X'here:

F = Side force at the bit caused by the weight of the unsupported section of the bottomhole assembly, lbs (daN).

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\\' = Buoyant weight of the unsupported section of the bottomhole assemblY, lbs (daN).

I = Hole inclination, degrees.

An increase in hole angle will result in an increase in F, resulting in an increase in dropping tendency.

H!GH

w

Figure 4-6 Drop Assemblies

HOLDING ASSEMBLIES Holding the inclination in a hole is much more difficult than building or dropping angle. Cnder ideal conditions, most assemblies either have a building or dropping tendency. Most straight hole sections of a directional well will have alternating build and drop tendencies. When holding inclination, these build and drop sections should be minimized and spread out over a large interval. The most common assemblies are indicated in Figure 4-6 indicating their strength at holding inclination.

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Figure ..:J.-6 Hold Assemblies

\\ben selecting a hold assembly, research the well records in the area to flnd out which assembly works best for the types of formations being drilled. If no formation is available, use a medium strength assembly and adjust it as necessary.

These build and drop assemblies are still used on directional wells but generally limited to slant hole drilling. The hold assemblies are very commonly used on deep \'ertical wells to minimize the amount of directional drilling required.

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EXAMPLE ROTARY ASSEMBLIES

Although their use is being minimized the rotary assembly still sees common use in certain fields. The follo-wing assemblies were successfully used in an area of shallow well drilling (500m) in Alberta. Note the subtle changes in BR\ and their effect on build/ drop rates. Their use has been severely curtailed due to the inev-itable trip to change the BHA and loss time incurred.

3 degree /30 "IdA mBUI b ssem lv Tool Description OD (mm) I Length (m) Bit 222 1 0.25 Near Bit Stabilizer 222 ' 1.50 3 -NMDC's I 171 I 27.00

2 degree/30m Build Assemblv .

Tool Description OD (mm) I Length (m) Bit 22.2 0.25 Near Bit Stabilizer I ')')') 1.50 .2- N.tviDC's i 171 18.00 NM Stabilizer I ')')') 1.50 ---1-NMDC 171 I 9.00

1 degree m Ul sem v /30 B "ld As bl Tool Description OD (mm) l Lengtl1 (m) Bit ')')') I 0 . .25

-.:...-

Near Bit Stabilizer .222 1.50 ShortNMDC ! 171 I 3.50 NM Stabilizer 216 1.50 1-NMDC 171 I 9.00 NM Stabilizer 2.2.2 I 1.50 1-NMDC i 171 9

Hold Assembly Tool Description OD (mm) Lengtl1 (m) Bit .22.2 I 0 . .25 Near Bit Stabilizer 222 1.50 ShortNMDC* 171 I 3.50 NM Stabilizer .222 1.50 1-NMDC 171 9.00 NM Stabilizer 222 1.50 1-NMDC 171 9 *change to full length NMDC and had less turn

21

3d egree /30 D m rop A bl ssem ly Tool Description I OD (nun) Length (m) Bit ~?') 0.25

---

Bit Sub I 1.50 ! NMDC 171 9.00 NM Stabilizer 222 1.50 1-NMDC 171 I 9.00 NM Stabilizer ~')'') I 1.50

---

1-NMDC 171 I 9.00

2d egree /30 D m rop A bl ssem ly Tool Description OD (mm) Length (m) Bit 222 I 0.25 Bit Sub I 1.50 Short NJ\IDC 171 I 3.50 NM Stabilizer ')")~ 1.50

---

1-NMDC I 171 9.00 NM Stabilizer i ")")") 1.50 .... __

1-NMDC I 171 I 9.00

1 degree/30m Drop Assembly Tool Description OD (nun) I Length (m) Bit 222 I 0.25 Near Bit Stabilizer I 216 I 1.50 I Short NMDC I 171 3.50 ~l\1 Stabilizer 222 I 1.50 1-NMDC 171 I 9.00 I NM Stabilizer I 222 1.50 I 1-NMDC I 171 9.00

JETTING The jet bit method of deflecting a well at one time was the most conunon method used in soft formations. Jetting has been successfully used to depths of 8,000 feet (2,400m); however the economics of this method and the availability of other directional drilling tools limit its use.

A formation suitable for jetting must be selected. There must be sufficient hydraulic horsepower available and the formation must be soft enough to be eroded by a mud stream through a jet nozzle.

22

There are special bits made for jetting including those with two cones and an elongated jet nozzle replacing the third cone. The elongated nozzle prm"i.des the means to jet the formation while the t\vo cones provide the mechanism for drilling. Other tri-cone deflection bits are available with an enlarged fluid entrance to one of the jets. This allmvs a greater amount of fluid to be pumped through one of the jets during jetting operations.

To deflect a well using the jet method, the assembly is run to the bottom of the hole, and the large jet is oriented in the desired direction. The kelly should be high to allow rotary drilling after the deflection is started. The centre of the large nozzle represents the tool face and is oriented in the desired direction. I\faximum circulation rate is used while jetting. Jet velocity for jetting should be 150 m/ sec (500' /sec).

The drill string is set on bottom and if the formation is sufficientk soft, the \X-OB drills off. A pocket is washed into the formation opposite the large nozzle. The bit and near-bit stabilizer work their way into the pocket (path of least resistance). Enough hole should be jetted to "bury" the near-bit stabilizer. If required, the bit can be pulled off bottom and the pocket spudded. The technique is to lift the string about 1.5m (5') off bottom and then let it fail, catching it ,vith the brake so that the stretch of the string (rather than the full weight of the string) causes it to spud on bottom. Spudding can be severe on drill string, drilling line and derrick and should be kept to a minimum. Another technique that may help is to 'rock' the rotary table a little (15) right and left of the orientation mark while jetting.

After a fe,v feet have been jetted, the pumps are cut back to about 50% of tl1.at used for jetting and the drill string is rotated. It may be necessary to pull off bottom momentarily due to high torque (near-bit stabilizer wedged in the pocket). High \'\70B and low RPM are used to try to bend the collars above the near-bit stabilizer and force the BHA to follow through the trend established while jetting. The remaining length on the kelly is drilled down. Deflection is produced in the direction of the pocket i.e. the direction in which the large jet nozzle was originally oriented.

To clean tl1e hole prior to connection/survey, the jet should be oriented in the direction of deviation. After surveying, this orientation setting (tool face setting) is adjusted as required, depending on the results achieved '.\rith the previous setting. Dogleg severity has to be watched carefully and reaming performed as required.

The operation is repeated as often as is necessary until sufficient inclination has been achieved and the well is heading in the desired direction. The hole inclination can then be built up to maximum angle using 100% rotary drilling and an appropriate angle build assemble.

23

1 Orientated a.nd Jettmg

Figure -1--7 Jetting Assembly

SPECIAL BHA's

Tandem Stabilizers

Steo '3 Re-Onentated

Jetting

It's fairly common to run a string stabilizer directly abm-e the near-bit stabilizer. This is normally for directional control purposes. An alternative is to run a near-bit '\Vith a longer gauge area for greater wall contact. High rotary torque may result in either case. It is dangerous to run tandem stabilizers directly after a more limber BHA due to the reaming required and potential sticking.

Roller Reamers

In medium/hard formations where rotary torque is excessive, it may be necessalT to dispense with some to all of the stabilization. Roller reamers are a good alternative however theY behave different then stabilizers. As a rule theY tend to

0 0

drop angle.

24

STABILIZATION

Consider the performance of two slick BHAs:

1) 200.0 mm Bit 2) 222.3 mm Bit 158.8 mm (6.25 inch) DC 158.8 mm (6.25 inch) DC

\\'hich of the two assemblies ha,e shown better perfonnance?

#1 had better performance because of better stabilization within the borehole during drilling. Comparatively, the service life of bit #2 is shortened because of a misaligned axis of rotation. This misalignment may be of a parallel or angular basis.

Parallel misalignment is caused by the use of a small drill collar in relation to the hole size and no stabilization. The bit can move off centre until the drill collar OD contacts the wall of the hole. This results in an offset due to drilling off centre (bottom of the hole shifts in a parallel manner and is called parallel misalignment).

Angular misalignment is caused by the use of small drill collars in relation to the hole size and no stabilization. Most or all of the bit load is applied to one cone at a time, causing rapid breakdown and failure of both the cutting structure and bearing structure of the bit.

Arthur Lubinski and Henry \voods (research engineers for Hughes Tool Co.) were among the first to apply mathematics to drilling. They stated in the early 50s that the size of the bottom drill collars would be the limiting factor for lateral movement of the bit, and the 1-1inimum Effective Hole Diameter (MEHD) could be calculated by the follmving equation:

MEHD Bit Size + Drill Collar OD 2

Robert S. Hoch (engineer for Phillips Petroleum Comp.) theorized that, while drilling with an unstable bit, an abrupt change can occur if hard ledges are encountered. He pointed out that a dogleg of this nature would cause an undersized hole, making it difficult or maybe impossible to run casing. Hoch rewrote Lubinski's equation to solve for the Minimum Permissible Bottom-Hole Drill Collar Outside Diameter (MPBHDCOD), as follows:

MPBHDCOD = 2 x (casing coupling OD) - Bit OD

25

Example: 311.2 mm bit 24-1-.5 mm casing (coupling OD 269.9 nun)

Minimum Drill Collar Size =,., x (269.9 mm) - 311.2 nun

= 228.6 mmOD

Bit misalignment can be controlled through use of appropriate size drill collars. An alternate method of control is through the use of stabilized bottom hole assemblies, particularly when drilling \vith diamond bits, journal bearing or sealed bearing bits.

Reasons for Using Stabilizers

1. The placement and gauge of stabilizers are used as the fundamental method of controlling the directional behavior of most bottom hole assemblies.

2. Stabilizers help concentrate the weight of the BHA on the drill bit.

3. Stabilizers resist loading the bit in any direction other than the hole axis.

4. Stabilizers minimize bending and vibrations, which cause tool joint wear and damage to BHA components such as, 1,1\\'D tools.

5. Stabilizers reduce drilling torque by preventing collar contact \Vith the side of the hole and by keeping the collars concentric in the hole but also add torque due to their side-loading.

6. Stabilizers help prevent differential sticking and key seating.

Available Types of Stabilizers

1. Integral blade stabilizers

2. \\'elded blade stabilizers

3. Replaceable sleeve stabilizers

4. Non-rotating rubber sleeve stabilizers

5. Replaceable wear pad stabilizers

6. Roller reamers

26

7. Combination reamers/stabilizers

Types of Stabilizers There are three basic types of stabilizing tools with some \'anauons of each available:

a) Rotating Blade Type b) Non-Rotating Slee\~e Type c) Roller Reamer Type

Rotating Blade Type

Can be a straight blade or a spiral blade (short or long blade) configuration.

Rotating blade stabilizers are available in two types - shop repairable - ng repairable.

"\re Integral Blade, \\'elded Blade or Shrunk on sleeve construction.

Integral Blade Stabilizer

They are made from one piece of material rolled and machined to provide the blades and are more expensive then welded-blade stabilizers.

The leading edge may be ronnded off to reduce wall damage and provide a greater wall contact area in soft formations.

They can have either three or four blades.

They normally have tnngsten carbide inserts (TCI). Pressed in TCI are recommended in abrasive formations i.e. hard limestone, dolomites, sandy shales, chert, quartzite, and quartzitic sands since they tend to stay in gauge longer than welded blade stabilizers.

Two main designs are available - spiral blade configuration for maximum wall contact and cloverleaf (straight blades) for less drag when not rotating. Integral blade stabilizers have longer blades and larger wall contact surface areas and are therefore good for maintaining angle and direction. They can be used as a near-bit stabilizer when angle build is required and a good rate of build \VW be obtained.

27

Welded Blade Stabilizers

The blades are welded onto the body in a high quality process that invokes pre-heating and post-heating all components and the assembled unit to ensure stabilizer integrity and minimize the possibility of blade failure. Blades can be straight, straight-offset, or spiral design.

They aren't recommended in hard formations because of the danger of blade failure. They are best suited to large hole sizes where the formation is softer because they allow maximum flo-w rates to be used. They are less expensi,-e to build than integral blade stabilizers and the blades can be built up 'vvhen they are worn.

The,- aren't recommended for use as the near-bit stabilizer in formations where bit walk is a problem because of the smaller area of blade/wall contact. The,- aren't as good as other stabilizer types for locking up an assembly so more walk (azimuth change) tends to occur.

Shrunk On Sleeve Stabilizers

~\ sleeve type integral blade stabilizer is constructed with the ribs integral '-"~th a slee,-e. The slee\-e is attached to the body with a shrink fit. \\ben ribs wear out, the old sleeve is removed with a cutting torch and a new sleeve shrunk on "'~th proper heating equipment.

Spiral or Straight Blade type

Either have a replaceable metal sleeve (i.e. Eze Change Stabilizer) or replaceable metal wear pads. They were originally developed for remote location use.

Non-Rotating Rubber Sleeve Stabilizers also fall into this area.

Non-Rotating Rubber Sleeve Stabilizers

Used somewhere above the top conventional stabilizer in the BHA, especially in abrasive formations. The rubber slen-e doesn't rotate while drilling and since the sleeve is stationary, it acts like a drill bushing and therefore will not dig into and damage the wall of the hole. The sleeve life may be shortened in holes "'~th rough walls. Special elastomer sleeves may be used for high temperature wells. Newer polymer design sleeves have been developed that may extend their use.

Replaceable Wear Pad Stabilizer

Has four long blades 90 apart composed of replaceable pads containing pressed-in tungsten carbide insert compacts. They are good for directional control and/ or in abrasive formations but may provide excessive torque.

28

Replaceable Sleeve-Type Stabilizer Tvw main designs of slee\e-n-pe stabilizer:

1. Two-Piece Stabilizer (mandrel and sleeve).

Sleeve is screwed onto the coarse threads on the outside of the mandrel and torqued to recommended value. Sleeve makeup torque is low and there is no pressure seal at the sleeve.

Convenient to change slee\es on the rig floor.

Hard-facing or tungsten carbide inserts protect the blade surfaces from wear.

One bodv can accommodate several sleeve sizes. Therefore are more economical than Integral Blade Stabilizers (easier to transport also).

Three-Piece Stabilizer (mandrel, sleeve and saver sub).

The sleeve is screwed onto the mandrel by hand initiallY. The saver sub is then screwed into the mandrel and this connection is torqued up to the required value. A mud pressure seal is situated at the mandrel/ saver sub connection.

Proper makeup torque is required to minimize downhole washing.

Since it can be time-consuming to change/service the sleeve, this t;.-pe of stabilizer is not as \v'.ideh- used today.

. .

Clamp-On Stabilizer

Several designs are available and allow more flexibilir;. in BI-L~ designs. They can be positioned on NMDCs, :M\\D tools, and PDM at required spacing for directional controL Nonmagnetic clamp-on stabilizers are also available. Risk exists of clamp-on mmmg position do\NTihole during drilling.

For any of the sleeve stabilizers one of the major disadvantages \\'.ith there use is the restrictions in circulation rates in smaller hole diameters - 8.5" (216 mm) or less because of the reduced clearance between the stabilizer bodv and the wall of the hole.

Roller Reamers

They are designed to maintain hole gauge, reduce torque and stabilize the drill string. They can be 3-point or 6-point design and both near-bit and string roller reamers are available. They are particularly useful in abrasive formations.

29

Near-bit roller reamers help prolong bit life and are normally bored out to accept a float valve. A near-bit roller reamer is sometimes used in place of a near-bit stabilizer where rotary torque is excessi,e. The disadvantage to this is that more bit walk is experienced since a smaller area of wall contact exists compared to other types of stabilizers. Also, lower build rates are obtainable \Vith roller reamers used as near bit stabilizers "'i.th building assemblies.

Selection of Stabilizer

Geology is an important consideration when choosing appropriate stabilizer for the well i.e. how hard is the formation? Cost and convenience also influence the selection of one stabilizer type over another. Stabilizer gauge influences the performance of the BHA, i.e. "'i.ll it build or drop angle as predicted? Or will the stabilizer wear prematurely in the formation being drilled?

Type of Stabilizer Integral Blade

\X.elded Blade

Replaceable Sleeve

Non-Rotating Rubber

Sleeve

Roller Reamers

Applications

Ivfaximum durability for toughest applications

Large hole size in soft formation. Top hole section of directional well (above KOP)

Valuable v:here logistics are a problem. Economic considerations.

Very hard and/ or abrasive formations.

Straight holes.

Hard formations.

Common BHA Problems

Formation Effects

It often happens that when a certain TVD is reached, BI-LA. behavior changes significantly. A BI-LA., which held inclination down is now starting to drop angle. \\11.y? Assuming that the near-bit has not gone under-gauge, it's probably due to formation effects (change in formation, change in dip or strike of the formation etc). It's vital to keep a good database and try to anticipate the problem for the following well.

Abrasive formations pose problems for the directional driller. Ensure the bit has good gauge protection and use stabilizers with good abrasion resistance. Check the gauge of the stabilizers when out of the hole and watch out for a groove cut on the leading edge of stabilizers (indication of need to change out the stabilizer).

30

\\11en it's difficult to drop inclination, sometimes a larger O.D. drill collar is used as the lower part of the pendulum. Another possibility is the use of a tungsten short collar; higher concentration of the same into a much shorter element should prov-ide a more effective pendulum force.

Worn Bits

In a long hole section in soft formation inter-bedded '.-Vith hard stringers, the long-toothed bit may get worn. ROP \Vill fall sharply and net side force ""'-ill decrease due to stabilizers undercutting the hole.

Thus, a BH.A. which had been holding inclination up to that point will start to drop angle. However, if the survey point is significantly behind the bit, this decrease in angle \\-ill not be seen in time. If the worn teeth are misinterpreted as a balled-up bit and continued lengthy efforts made to drill further, serious damage may be done to the hole. It has happened that a drop in inclination of 6 (\vith a severe dogleg se\erity) has happened in this situation. In addition, a bit having worn teeth has a tendency to lose direction. Thus, it is important to pull out of the hole when a worn bit situation develops.

Accidental Sidetrack

In soft formation, where a multi-stabilizer BHA (either Buildup or Loch.-up) is run inunediately after a mud motor/bent sub kickoff run, great care must he taken. Circulation should be broken just before the kickoff point. The BI-L-\ should be \Vashed/worked down, using full flow rate. The directional driller must be on the drill floor while this is happening. Try to work through tight spots. If string rotation is absolutely necessary, keep the RPM low and cut rotating time to the absolute minimum. The risk of sidetracking the well (with subsequent expensive plug-back andre-drill) is high. Several kickoffs have been lost in various parts of tl1e world b\ carelessness.

\\bere tl1e kickoff is done in a pilot hole in soft formation, an under-reamer or hole opener is used to open the hole prior to running casing. Again, to avoid an unwanted sidetrack, a bull-nose (not a bit) and possibly an extension sub/short collar should be run below the under-reamer/hole opener.

Pinched Bit

In hard formations, it is especially important to check each bit for gauge wear etc. when it's pulled out of the hole. \\ben running in the hole \vith a new bit and/ or BHA, it's imperative that the driller starts reaming at the first sign of under-gauge hole (string taking weight). If he tries to "cram" the bit to bottom, it will become "pinched". Bit life will be very short.

31

Differential Sticking

\\bere differential sticking is a problem, more than three stabilizers may be run in an effort to minimize wall contact with the drill collars. However, the distance between these "extra" stabilizers normally has to be such that theY ha,~e little effect. They only lead to increased rotary torque. It is \'"ital to mirumize ume taken for surveys (even "I.V,j_th l\1\\'D) in a potential differential sticking area.

Drilling Parameters

High rotary/ top drive RPM acts to stiffen the string. Thus for directional control, if possible, high RPJ\I should be used during the rotar: buildup phase, when the BHA is most limber. However, it's vital to check with the l\1\XD engineer for an acceptable range of RPM (to a\~oid resonance). On a new job, tl1e rig specifications (particularly mud pumps and draW\vorks) should be checked "",j_th the toolpusher.

Typical values in 17-1/ 2" ( -+-+-+mm) hole during rotar: build/lockup phases "",j_tl1 a milled-tooth bit would be 160-170 RPJ\I. The rotary transmission would normally

. .

have to be put into high gear. In 12-1/4" (311mm) hole, RPJ\I is normally less (e.g. 100-14-0), due to bit life and other factors.

Conversely, to induce right-hand walk, it's recommended to slow the RPM (if the hole direction allows). \\'eight on bit may be simultaneously increased, if the hole inclination allows.

PDC bits normallY have a tendency to walk left. This should be allowed for when . .

planning the lead angle at the pre-kickoff stage. Again, experience in the area and "I.V,j_th the bit has to be used in making this decision.

To increase rate of buildup, increase the weight on bit. Tlus is normallY tl1e case. However, when the \\'OB reaches a certain value, reverse bending may occur when using a flexible buildup BHA (e.g. 90' between near-bit and bottom string stabilizers). Suggested maximum value of\X'OB for 17 1/2" hole is 55,000 lbs. If inclination is not building enough at this \VOB, it's ,~er: unlikely that increasing the \\"OB "",j_ll improve the situation. Look to hydraulics or possibly pull out of the hole for a more limber hook-up.

It's \'"ital that the directional driller observes the buildup rate carefully. Drilling parameters normally have to be changed ver: often (typically after every survey). \\'itl1 l\1\\'D, there's no excuse for not keeping close control of buildup rate. Most operators will not complain about taking too many surveys if they know the risk but get rather upset if the well goes off course due to insufficient control.

32

BHA Equipment and Tools

It's the joint responsibility of the directional driller and operator to ensure that everything needed (within reason) for future BI-L,;.'s is anilable on the rig. ",;_ll the directional equipment must be checked thoroughly on arrival at the rig-site.

For rotary BHA's, following are some suggestions:

A selection of stabilizers (normally a combination of sleeve- type and integral blade design for 17-1 / .2" and smaller hole sizes) v\i.th 360 wall cm-erage should be av-ailable.

Short drill collars are a vital component of a lockup BI-L,;.. If possible, a selection of short collars (e.g. 5', 10, and 15) should be available. In addition, in a well where magnetic interference from the drill string (mud motor) is expected to be a problem during the buildup phase, non-magnetic (rather than steel) short collars should be pro-v-ided.

Check that the rig has sufficient drill collars and H\\'DP av-ailable.

Check that sufficient bit nozzles of each size (including what's needed when running a mud motor) are av-ailable.

Have at least one spare non-magnetic drill collar of each size. As NMDC's are more prone to galling, damaged collars should be returned to the shop for re-cutting/ re-facing when replacements arrive.

Any crossover subs, float subs, bit subs etc. required later must be on the rig.

It's a good idea to be thinking at least one BI-L,;_ ahead!

Recap

To build inclination, always use a full-gauge near-bit stabilizer.

The more limber the bottom collar, the greater the buildup rate achievable.

Take frequent surveys (e.g. every single with l'vf\X'D) during the buildup phase (all wells) and the drop-off phase ('S"-type wells) in order to react quickly to unexpected trends.

A jetting BHA is a modified buildup BHA. Don't jet too far! \\'atch the ~'0 B available for jetting/ spudding.

33

To drop inclination, either use an under-gauge near-bit (semi-drop BfL\, for low drop-off rate) or no near-bit (pendulum BHA, for sharp drop-off rate).

A locked BfLA.., which is holding inclination \vith an under-gauge stabilizer above the short collar, "\Vill start to drop inclination if this stabilizer is made full-gauge.

In an "S"-type well, try to start the drop-off early using a semi-drop BHA. Change to a pendulum BHA at around an inclination of 15.

Try not to have to build inclination into the target; it is better to drop slowly into the target.

Three stabilizers are normallY sufficient in a BHA. In pendulum BfL \'s, two stabilizers should suffice.

Cse as few drill collars as possible. Cse heavyweight drill pipe as remaining anilable weight on bit.

Try to use a fairly standard (reasonably predictable) BHA. Do not try any "fancy" BHA's in a nev: area. Get some experience in the field first!

Directional driller should be on the drill floor when washing/working rotary BHA through kickoff section in soft formation. Avoid sidetracking the well!

After a kickoff or correction run in medium and hard formations, ream carefully through the motor run \vith the following rotary BHA until hole drag is normal.

In hard and/ or abrasive formations, gauge stabilizers carefully when POOH . Replace stabilizers as required. Check the bit and if it is under-gauge, reaming \vill be required! Do not let the driller "pinch" the bit in hard formation.

Check all directional equipment before and after the job. It's good practice to caliper all the tools and leave list on drill floor for drillers. \\'atch out for galled shoulders!

In potential differential sticking areas, minimize survey time. If using single-shot surveys, reciprocate pipe. Leave pipe still only for minimum time required.

A BHA that behaves perfectly in one area, may act very differently in another area. Local experience is essential in 'fme-tuning" the BfLA..'s.

34

In the tangent section of a well, a BHc\ change may simply entail changing the sleeve on the stabilizer directly abm-e the short collar. The trick is by hmv much should you change the gauge? Sometirnes a change in gauge of 1/16" may lead to a significant change in BR\ behavior!

High RPM 'stiffens" the BHA and helps to stop walk due to formation tendencies.

It's usuallY easier to build inclination \vith lower RPM. However, high RP.t\I during the buildup phase may be required for directional control. \\-OB is tl1e major drilling parameter influencing buildup rate.

To help initiate right-hand walk, it's ad\-isable to use higher WOB and lo\\er RPM.

In soft formation, it may be nece"sary to reduce mud flow rate to get sufficient \\"OB and reduce hole washout. Be careful! \\'ash each joint/ stand at normal flow rate before making the connection.

Reaming is effective in controlling buildup rate in soft formation. It becomes less effective as formation gets harder. Howe\er, even in hard formation, reaming before each connection helps keep hole drag low.

Lower dogleg severity = smoother wellbore = lower friction = lower rotary torque = less keyseat problems = less wear on tubulars = less problems on trips.

WHIPSTOCK

The retrie\able open-hole whipstock is an old directional drilling tool, which is seldom used in open-hole deflections today. The whipstock is pinned to a lin1ber BHc\ which includes a small bit. A typical BHc\ would be as follows:

Whipstock - pilot bit - stabilizer - shearpin sub - 1 joint of drill pipe - CBHO (to single shot survey) -non-magnetic drill collar

The hole must be clean before running the whipstock. Upon reaching bottom the tool is pulled up slightly off-bottom and the concave face of the whipstock is oriented in the desired direction. The tool is then oriented in the desired direction and set on bottom. The toe of the wedge is anchored firmly in place by appl~-ing sufficient weight to shear the pin. The bit is lowered down the whipstock face and rotation is started. About 15 to 20 feet ( 4.5 to 6m) of rathole is drilled at a controlled rate. The whipstock is then retrieved and the rathole is opened \vith a pilot bit and hole-opener. Another trip with a full-gauge bit, near-bit stabilizer and

35

limber BfL~ is made to drill another 30' (9m). ~~ full gauge directional BfL~ is then run and standard drilling is resumed.

This is a very time consuming method of open-hole deflection and creates an abrupt change in inclination or dogleg (typically l-i0 to 20 per 100 feet or 30 meters) . A permanent whipstock could also be run but the risks of the whipstock falling over or shifting after time is generally thought to be too large.

DOWNHOLE MOTORS WITH BENT SUB

The use of downhole bent subs has been severelY reduced with the invention of steerable motors but is still used in some areas with turbodrill and positi\'e displacement motors, in conjunction to achieve higher build rates and '.vhen other choices are not available.

Turbodrills were first used in the 1800's with limited success due to their high RPM (SOO to 1200). The use of turbodrills were limited as a deflection tool as well due to their low torque output. The rotation of a turbodrill is derived from the interaction of the drilling fluid and the multiple stages of turbine blades. The rpm's are directly related to the fluid velocity and torque. One disadvantage of the turbodrill is that the efficiency is lower than the positive displacement motor. Therefore, it requires more horsepower at tl1e surface. Many rigs do not have enough hydraulic horsepower to run a turbodrill. The hydraulics should always be checked prior to running a turbodrill.

The positive displacement motor uses the Moyna principle. This tool has found '.vide application in directional drilling and even straight hole performance drilling. The basic design and components of a positi'.'e displacement motor "\Vill be discussed in a later section.

The best application of the pos1t1ve displacement motor is in moderately soft formations. \\ben the formation is too soft, the motor is not as effective as jetting. In hard formations, the motor is slow and expensive to use.

Both the positive displacement motor and the turbodrill exhibit reverse torque (reactive torque) when placed on the bottom of the hole. This must be taken into account when orienting the motor. Experience in the area is the best method of predicting the reverse torque. If no other information is available, a rule of thumb can be used. That is allow 10 of left torque per 1,000 feet (3 per lOOm) of depth in soft formations and so /1,000 feet (1.5 per lOOm) of depth in hard formations. If the change in well course is critical, steerable motors with J\.1\\TI equipment should be used.

The downhole motor has a distinct advantage over jetting and whipstocks. Doglegs created by jetting and whipstocks are more severe than tl1ose created by a

38

downhole motor. Jetting and -.,.vhipstocks create abrupt changes in angle and direction. On the other hand, downhole motors produce a smooth arc m"er an extended length of the wellbore, and the dogleg severity can be controlled by the angle of the bent sub used.

The basic drilling assembly for using a downhole motor consists of a full gauge bit, motor, bent sub, mule shoe sub (some bent subs incorporate a mule shoe sleen:), and non-magnetic drill collars. The bent sub has one of the connecting threads machined at an angle to the axis of the body of the sub. It imparts the bending force in the assembly as drilling progresses, thus producing a change in hole direction. Under dynamic conditions, the side force at the bit is relati-.,."ely constant. This is the reason the downhole motor produces a continuous change in the wellbore course along a smooth arc of a circle. Because of the high bit offset '-"'ith this assemble it is advisable to not rotate this type of BHA.

Csing downhole motors to deflect deep wells can minimize some of the problems associated \\>'ith shallow, severe doglegs. These problems are drill pipe fatigue, drill string wear, casing wear, keyseats, torque, drag, and production problems. \\11en drilling directional wells, changes in the dogleg severity should be minimized to prevent problems but it depends on the depth of the dogleg. All changes should be as gradual as possible and still accomplish the objectives.

STEERABLE ASSEMBLY

A steerable assemblY is deflned as a bottomhole assemblY whose directional . .

behavior can be modified by adjustment of surface controllable drilling parameters including rotary speed and weight on bit. The ability to modify behavior in this way enables the assembly to be steered toward a desired objecti\"e \N'ithout its removal from the wellbore. To some extent, rotary assemblies are steerable if the build m drop tendency is weight sensitive. However, the ability to control a rotar:r assembly is limited especially controlling walk.

The most common steerable assembly consists of a PDl\I that incorporates a fLxed or adjustable bent housing on top of the bearing housing below the stator. With the smaller displacement of the bit as compared to using a bent sub, the motor can be safely rotated at RPM's up to 50 depending upon the bend setting and formation. The motor housing may also incorporate an 3mm (1/8") undergauge stabilizer. \\lith the bent housing, the stabilizer is not required but the hold tendency of the assembly in the rotar: mode is improved.

The steerable system operates in two modes; sliding and rotar: drilling. In the slide mode, the motor acts like a typical motor run. The motor is miented in the desired direction (tool face), and drilling progresses without drill pipe rotation. The change in inclination and or direction is derived from the bit tilt from the

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bent housing and the side force created from the stabilizer or the wall contact \vith the motor.

In the rotary drilling mode, the assembly is rotated per normal but at lower ,~alues (30 to SO RPJ\1) and d1e side force is cancelled by this rotary action. In some formations the assembly 'W111 change inclination/ direction even in the rotary mode. Because of d1e bit offset or the side force associated \v'ith a steerable system, d1e assembly 'W111 drill an overgauge hole in the rotary mode.

Advances in downhole motor reliabilitY have made the steerable system economical in many applications. Typically, the mean time between failure is in excess of 2000 hours for the motor and excess of 800 hours for the measurement while drilling equipment thereby exceeding d1e life of a tri-cone bit. \\bere feasible, the tri-cone bit has been replaced with a PDC or diamond bit. \\ben properly matched to the formation and motor torque output, a PDC bit can last much longer than a tri-cone bit; however, a PDC bit can not always be used. They are applicable to soft and medium hardness formations with consistent lithology. In areas where formation hardness changes a lot, PDC bits do not perform as well as tri-cone bits. Also the ability or ease of controlling build and turn rates of a PDC van~ considerablY.

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In some cases, the penetration rate of a steerable system \\W out perform d1at of a rotary assembly. The majority of the time, it is used in soft formations. As formation hardness increases, rotary assemblies 'vvW drill faster than a steerable system unless special high torque performance motors are used. Harder formations are less sensitive to rotary speed, and bit weight is the predominant drilling parameter. In hard formations, the penetration rate for a motor can be half that of a rotary assembly. In soft to medium hard formations, the penetration rate for a downhole motor has been t'W'ice that of a rotarY assembh~.

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"\s the torque and drag in a directional well increases, the rate of penetration for a steerable system while sliding can be considerably less than while rotating. In some cases it will be half d1e rate seen while rotating. Therefore, it is advantageous to rotate a steerable sntem as much as possible especially when approaching TD.

The directional plan can be followed much more closely with a steerable system. Since trips are not required, corrections in the slide mode are made much more frequently. The frequent corrections \NW keep the wellbore closer to the planned path. In the hold section, the directional driller will often rotate for a portion of a connection and slide for the remainder of ilie connection. He must first get a feel for how much ilie assembly is walking and building or dropping while in the rotary mode. Once he gets a feel for iliat then he can determine how much he needs to slide per connection and what ilie tool face orientation must be.

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This does not mean that the dogleg severi0 is very low. It only means that the changes are small and frequent. StuTeys at 20m to 30m inteJTals vvillnot pick up the actual dogleg severi0 in the v\ell. \X'hereas with rotaty assemblies and motor corrections, the dogleg severi0 is picked up by the surveys. Frequent motor corrections (short dogleg intervals) will minimize problems associated \\'"i.th keyseats. The doglegs are not long enough for keyseats to form easily.

The steerable system should be designed to generate a dogleg severi0 25 percent greater than that required to accomplish the objectives of the directional plan (a more aggressive bent housing setting). Formation tendencies can cause the dogleg severi0 of a steerable system to change. If it decreases the dogleg severitv generated by the system, then a trip may be require to pick up a more aggressive assembly. However if the assembly is designed to be more aggressive, then the assembly will still be able to produce a dogleg severi0 sufficient to keep the wellbore on course and less slide drilling is required resulting in a higher average ROP. Reducing the dogleg severi0 of a steerable system is not a problem. Alternately sliding and rotating the assembly \\'ill reduce the overall dogleg severitv.

The most significant advantage of the steerable system is that a trip does not have to be made in order to make a course correction. \X11en a correction is required, the motor is oriented and drilling continues in the slide mode until the correction is complete. Then drilling in the rotary mode continues until the next correction is required. If a steerable system is not used, a trip would be required to pick up a motor assembly before making the correction. After the correction is made, another trip would be required to pick up the rotary assembly.

Another advantage of the steerable system is that it prov'ides the abilitv to hit smaller targets at a reasonable cost. Because a trip is not required to make a course correction, the steerable system can hit a smaller target vv'ith less cost. It's not that a small target can not be hit using rotary assemblies and motor corrections; its that the costs increase significantly as the target gets smaller.

Steerable systems are 0-pically used in drilling multi-target directional and horizontal wells. Drilling through a cluster of wells is another good application for a steerable system. Drilling out from under a crowded platform may require building, dropping and turning at various rates over a relatively short distance in order to avoid other wellbores. A steerable system is capable of making all the corrections without tripping. In an emnonment where the daily operating costs are high, the steerable system can result in significant savings.

Just because the industry has the capability to hit smaller targets does not mean that the targets should be undulv restricted. The smaller the target, the more expensive it can be to hit. \X'ith a

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steerable system, the cost differential isn't as high as it 'Nould be using rotary assemblies and making motor corrections.

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Chapter

DOWNHOLE MUD MOTORS There are two major types of downhole motors powered by mud flow; 1) the turbine, which is basically a centrifugal or axial pump and 2) the positi\~e displacement mud motor (PDJ\1). The principles of operation are shown in Figure 7.1 and the design of the tool are totally different. Turbines were in wide use a number of years ago and are seeing some increased use lately but the PDM is the main workhorse for directional drilling.

Turbine Motor Positive Displacement Motor

Figure 7-1 Motor Types

Motor Selection

Four configurations of drilling motors prm,ide the broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications. These configurations include:

High Speed I Low Torque

Medium Speed I Medium Torque

Low Speed I High Torque

Low Speed I High Torque -Gear Reduced

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The high speed drilling motor utilizes a 1:2 lobe power section to produce high speeds and luw torque outputs. They are popular choices when drilling with a diamond bit, tri-cone bit drilling in soft formations and directional applications where single shot orientations are being used.

The medium speed drilling motor typically utilizes a -t-:5 lobe power secnon to produce medium speeds and medium torque outputs. They are commonly used in most conventional directional and horizontal wells, in diamond bit and coring applications, as well as sidetracking.

The low speed drilling motor typically utilizes a 7:8 lobe power section to produce low speeds and high torque outputs. They are used in directional and horizontal wells, medium to hard formation drilling, and PDC bit drilling applications.

The gear reduced drilling motor combines a patented gear reduction system with a 1:2 lobe high speed po"\ver section. This system reduces the output speed of the 1:2 lobe power section by a factor of three, and increases the output torque by a factor of three. The result is a drilling motor \V"ith similar performance outputs as a low speed drilling motor, but \V"ith some signitlcant benetlts. The 1:2 lobe power section is more efticient at converting hydraulic power to mechanical power than a multi-lobe power section and also maintains more consistent bit speed as weight on bit is applied. This motor can be used in directional and horizontal wells, hard formation drilling, and PDC bit drilling applications.

Some other motor selections are also available including a tandem and moditled motor. These ,~ariations are described belo"\v.

Tandem Drilling Motor- The drilling motor utilizes two linked power sections for increased torque capacity.

:tvloditied Drilling Motor - The bearing section of the drilling motor has been moditled to prm~ide different drilling characteristics (ie. change bit to bend distance, etc.).

Components

All drilling motors consist of tlve major assemblies:

1. Dump Sub Assembly

2. Power Section

3. Drive Assembb:

-t-. Adjustable Assembly

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5. Sealed or l\Iud Lubricated Bearing Section.

The gear reduced drilling motor contains an additional section, the gear reducer assembly located within the sealed bearing section. Some other motor manufacturers have bearing sections that are lubricated by the drilling tluid.

Dump Sub Assembly

.~s a result of the power section (described below), the drilling motor will seal off the drill string ID from the annulus. In order to prevent wet trips and pressure problems, a dump sub assembly is utilized. The dump sub assembly is a hydraulically actuated vah'e located at the top of the drilling motor that allm\'S the drill string to till "\vhen running in hole, and drain when tripping out of hole. \\ben the pumps are engaged, the valve automatically closes and directs all drilling tluid tlow through the motor.

In the e\'ent that the dump sub assembly is not required, such as in underbalanced drilling using nitrogen gas or air, it's effect can be negated by simply replacing the discharge plugs with blank plugs. This allows the motor to be adjusted as necessary, even in the field. Drilling motors 95 mm (3 3/ 4") and smaller require the dump sub assembly to be replaced with a special blank sub.

Power Section

The drilling motor power section is an adaptation of the Moineau type positive displacement hydraulic pump in a reversed application. It essentially converts hydraulic power from the drilling tluid into mechanical power to drive the bit.

The po"\ver section is comprised of two components; the stator and the rotor. The stator consists of a steel tube that contains a bonded elastomer insert with a lobed, helical pattern bore through the centre. The rotor is a lobed, helical steel rod. \\ben the rotor is installed into the stator, the combination of the helical shapes and lobes form sealed cavities between the two components. \\ben drilling tluid is forced through the power section, the pressure drop across the cavities will cause the rotor to turn inside the stator. This is how the drilling motor is powered.

It is the pattern of the lobes and the length of the heli.x that dictate what output characteristics will be developed by the power section. By the nature of the design, the stator always has one more lobe than the rotor. The illustrations in Figure 7-2 show a 1:2 lobe cross-section, a 4:5 lobe cross-section and a 7:8 lobe cross-section. Generally, as the lobe ratio is increased, the speed of rotation is decreased.

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7:l.lL.08E

Figure 7-'2: Cross-sections of the most common power section lobe configurations

The second control on power section output characteristics is length. ~A. stage is defined as a full helical rotation of the lobed stator. Therefore, power sections may be classified in stages. A four stage power section contains one more full rotation to the stator elastomer, when compared to a three stage. \\'ith more stages, the power section is capable of greater m-erall pressure differential, which in turn provides more torque to the rotor.

As mentioned above, these two design characteristics can be used to control the output characteristics of any size power section. This allows for the modular design of drilling motors making it possible to simply replace power sections when different output characteristics are required.

In addition, the variation of dimensions and materials \Vill allow for specialized drilling conditions. \\'ith increased temperatures, or certain drilling fluids, the stator elastomer will expand and form a tighter seal onto the rotor and create more of an interference fit, which may result in stator elastomer damage. Special stator materials or interference fit can be requested for these conditions.

Drive Assembly

Due to the design nature of the power section, there is an eccentric rotation of the rotor inside of the stator. To compensate for this eccentric motion and convert it to a purely concentric rotation drilling motors utilize a high strength jointed drive assembk The drive assemblY consists of a drive shaft with a sealed and lubricated

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drive joint located at each end. The drive joints are designed to 'Wi.thstand the high torque values delivered by the power section while creating minimal stress through the drive assembly components for extended life and increased reliability. The drive assembly also provides a point in the drive line that 'Wi.ll compensate for the bend in the drilling motor required for directional control.

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Adjustable Assembly Most drilling motors today are supplied with a surface adjustable assembh-. The adjustable assembly can be set from zero to three degrees in \'arying incre~ents in the field. Tlus durable design results in "\vide range of potential build rates used in directional, horizontal and re-entry wells. Also, to mininUze the wear to the adjustable components, wear pads are normally located directly abm-e and below the adjustable bend.

Sealed or Mud Lubricated Bearing Section

The bearing section contains tl1e radial and thrust bearings and busl-llngs. They transmit the axial and radial loads from the bit to the drill string while providing a drive line that allows the power section to rotate the bit. The bearing section may utilize sealed, oil filled, and pressure compensated or mud lubricated assemblies. \\'ith a sealed assembly the bearings are not subjected to drilling fluid and should provide extended, reliable operation with minimal wear. As no drilling fluid is used to lubricate tl1e drilling motor bearings, all fluid can be directed to the bit for maximized hydraulic efficiency. This provides for improved bottom-hole cleaning, resulting in increased penetration rates and longer bit life. The mud lubricated designs typically use tungsten carbide-coated sleeves to provide the radial support. Usually ..J.% to 10% of the drilling fluid is diverted pass tlus assembly to cool and lubricate tl1e shaft, radial and thrust bearings. The fluid then exits to the annulus directly above tl1e bit/ drive sub.

Gear Reducer Assembly

An alternative to the type low speed drilling motor is the gear reduced design. It utilizes a gear reduction assembly \\1.thin the sealed bearing section in combination \"\1.th a 1:2 lobe power section. This patented design reduces the speed of rotation by a factor of three while increasing the torque by the same multiple. The benefit with this design is increased stability in the bit speed for different differential pressures, and improved hydraulic efficiency out of tl1e power section.

Kick Pads

Most drilling motors can incorporate wear pads directly above and below the adjustable bend for imprm-ed wear resistance. Eccentric kick pads can also be used on most motors ranging from 121 mm (4 3/4') to 24.5 mm (9 5/8") in size. This kick pad is adjustable to match the low side of the motor to increase build rate capabilities. It will also allow lower adjustable settings for similar build rates, thereby reducing radial stresses applied to the bearing assembly, and permit safer rotation of the motor. They can be installed in the field by screwing them onto specially adapted bearing housings.

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Figure 7-3 General motor component layout

Stabilization

Bearing housings are also available with two stabilization styles, integral blade and screw-on. The integral blade style is built directly onto the bearing housing and thus cannot be removed in the field. The screw-on style provides the option of installing a threaded stabilizer sleeve onto the drilling motor on the rig floor in a

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matter of minutes. The drilling motor has a thread on the bottom end that is cm~ered \Vith a thread protector slee\Te when not required. Both of these stvles are optional to a standard bladed bearing housing. .

Drilling Motor Operation

In order to get the best performance and optimum life of drilling motors, the following standard procedures should be followed during operation. Slight variations may be required with changes in drilling conditions and drilling equipment, but attempts should be made to follow these procedures as closely as possible.

Assembly Procedure & Surface Check Prior to Running in Hole

Most motors are shipped from the shop thoroughly inspected and tested, but some initial checks should be completed prior to running in hole. TI1ese surface check procedures should only be used \vith mud drilling systems. To avoid potential bit, motor, and BOP damage, these preliminary checks should be completed \vithout a bit attached. A thread protector should be installed in the bit box whenever moving the motor, but must be removed before flow testing.

1. The correct lift sub must always be installed and used for moving the t