IADC Drilling Manual Part 11 ppsx

P-64 International Association of Drilling ContractorsIADC Drilling Manual - Eleventh Edition Magnets are sometimes used in non-magnetic drill collars by the Directional Driller for orie

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International Association of Drilling Contractors

Chapter P: Hole Deviation and Horizontal Drilling

11 Do not permit rig driller to drill through bridges encountered on trips in the hole without the directional sor being present

supervi-12 Instruct the directional drilling supervisor in keeping drilling records your company will require

IV Sub Surface Surveying

A Surveying Instruments

1 Single Shot

A magnetic survey instrument consists of a compass, inclination unit, camera section, batteries and a time device.This instrument records drift angle and direction of the hole data on a single film disc This instrument is used bythe directional supervisor during drilling operations

2 Multi-Shot

A magnetic survey instrument that consists of the same elements as a single shot instrument except multiplereadings of drift angle and direction are recorded on movie film This instrument can be dropped in the hole andlanded inside of a nonmagnetic collar to record many survey stations on trips in or out of the hole

3 Gyroscope

This type of survey instrument can record single or multi-shot surveys depending on the type of timing device andcamera unit used This instrument must have a known direction to set its pointer toward and all hole directions arereferenced from the known direction The instrument can be used inside of a cased hole because it is not affected

by magnetized pipe or influenced by formations that would affect a magnetic compass

B Non-Magnetic Drill Collars

The maximum length of non-magnetic drill collar required can be determined by referring to Figures P2-5,

Figure P2-6 and Figure P2-7

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P-63

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P-64 International Association of Drilling Contractors

IADC Drilling Manual - Eleventh Edition

Magnets are sometimes used in non-magnetic drill collars by the Directional Driller for orientation only, and should

be replaced with brass pugs when they are not required for orientation

C Surveying Procedure

All Surveys should be reported as located at the angle unit depth Report all acceptable surveys (exclude tion surveys) The IADC API drilling report is the place to record each bottom assembly used

orienta-1 Location of Baffle Plate

The baffle plate for the survey instrument should be located at the bottom of the bottom non-magnetic drill collar

2 Declination

The difference between true north and magnetic north is declination The declination varies around the world asshown on the example Isogonic Chart attached, Figure 2-8

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Notes for Figure P2-8 Isogonic Chart

Magnetic declination (also called "variation of the compass") is here shown as of the beginning of 1975 by means

of isogonic lines, i.e lines of equal declination These lines are solid in the area where the compass points east oftrue north, and broken in the area where it points west of true north

The lines are drawn to show a relatively smooth distribution The irregularities remaining in the lines, particularlythe local anomalies, rather than as a close representation of the declination,

If Disc Reading EAST DECLINATION WEST DECLINATION

(Add in Azimuth) (Subtract in Azimuth)

NE ADD to reading SUBTRACT from reading

SE SUBTRACT from reading ADD to reading

SW ADD to reading SUBTRACT from reading

NW SUBTRACT from reading ADD to reading

Magnetic declination (also called "variation of the compass") is here shown as of the beginning of 1975 by means

of isogonic lines, i.e lines of equal declination These lines are solid in the area where the compass points east oftrue north, and broken in the area where it points west of true north

The lines are drawn to show a relatively smooth distribution The irregularities remaining in the lines, particularlythe local anomalies, rather than as a close representation of the declination,

If Disc Reading EAST DECLINATION WEST DECLINATION

(Add in Azimuth) (Subtract in Azimuth)

NE ADD to reading SUBTRACT from reading

SE SUBTRACT from reading ADD to reading

SW ADD to reading SUBTRACT from reading

NW SUBTRACT from reading ADD to reading

There is an annual variation in declination The chart used must be up to date The declination can be corrected

to true north or to grid north The correction will be made to true north unless stated otherwise in the drillingprogram or directional plat

3 Calculation of Surveys

The radius of curvature method is the most accurate way to calculate a directional survey This is usually done bymeans of a computer or programmable pocket calculator However, the balanced tangential or vector averagingmethod approaches the accuracy of the radius of curvature method and is usually used by directional drillingsupervisors in the field

V Deflection Tools

A Downhole Motors

The downhole mud motor has replaced the Whipstock as the primary tool to deviate the direction of a wellbore.The mud motor function is to rotate the bit when a bent sub assembly is used This eliminates drill string rotationand the well bore is deviated in the direction of the oriented bent sub The deviation assembly is made up of anonmagnetic collar, a bent sub, a mud motor and the drilling bit The downhole mud motor is either a positive

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displacement type or a turbine The motor size is determined by the size of the bit being run Performance teristics are given in Table P2-1 and Table P2-2

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charac-IADC Drilling Manual - Eleventh Edition

Dog-leg expectancy is a function of the assembly geometry and not the type of mud motor You would expect todevelop the same rate of hole deviation change if the bent sub angle, motor O.D and length and average weight

on bit are the same regardless of the type of mud motor

When a turbine is used, a screen should be placed between the kelly and the drill pipe to insure against foreignmaterial being pumped through the turbine and causing a motor failure If the mud system is using lost circulationmaterial, the screen procedure is not feasible and a turbine should not be used

2 Positive Displacement Mud Motor

The positive displacement mud motor runs at lower RPM for a given mud volume than the turbine Large diametertricone bits with high torque requirements are easily handled Tool operating data is given in Table P2-1

The positive displacement motor torque varies in a direct ratio to the pressure differential across the motor Thisprovides surface indication on the mud pump gauge Increasing bit torque up to stall conditions can be monitored.Lost circulation material in the mud is normally handled by positive displacement motors without problems

B Whipstocks

The removable whipstock is a reliable deflection tool that is usually used when jetting or when downhole motorscannot be used It is a cylindrical steel casting, five to thirteen feet long, with a ring at the top, a concave inclinedgroove formed on one side and a chisel point bottom The ring at the top is smaller than the bit and provides themeans of transporting the whipstock in and out of the hole The chisel bottom holds the whipstock stationary when

it is set, and the indented groove, (usually 3 degrees) guides the bit to a new course

There are two types of whipstocks:

1) the bottom circulating in Figure 2-9a and

2) the standard or conventional shown in Figure 2-9b

Figure P2-9 Whipstocks

The circulating whipstock differs from the standard whipstock, in that there is a control sub immediately above thebit that prevents the flow of circulating fluid through the bit and deflects it through a hollow shear pin used to pinthe whipstock to the drill pipe assembly The flow of fluid passes through the shear pin and down to the bottom ofthe whipstock via a bored circulating channel in the back of the whipstock The fluid then flows out the bottom of

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the whipstock This permits the bridges in the hole to be washed through, and fill up on the bottom of the hole to becirculated clean

Prior to setting the whipstock, a ball is dropped through the drill pipe and seated in the control sub The drilling fluid

is then diverted from the bottom of the whipstock and established through the bit The whipstock can then be setand drilling commenced

A 15' - 20' rat hole is usually drilled below the whipstock setting point The diameter of this hole is smaller than theopen hole, and must be reamed out to the full hole size by means of a hole opener Therefore, setting a whipstock

is slower than other deflection tool methods because more trip time is needed to set and ream the rat hole out tofull gauge

A combination universal knuckle joint and short drill collar may be run in conjunction with the whipstock whenextreme angles are required to sidetrack an enlarged hole

C Jetting

Holes in soft formations are usually deviated by using a bit which has all but one of the nozzles closed off, orsubstantially reduced in size One 3/4" or 5/8" nozzle and two 1/4" nozzles are popular sizes frequently used Touse, an angle building assembly (see Fig 10) and jet bit designed for deviation jetting is run in the hole and oriented

in the desired direction

Figure P2-10 Jetting for Directional Control

Notes for Figure P2-10

A Washing action by large jet (left)

B When rotation is started stabilizer smooths out dog-leg on high side (middle)

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C After initial deflection has been accomplished, stabilizer acts as a fulcrum for continuing the hole curvature(right)

A high rate of circulation is established and the bit with weight applied is set on bottom Fluid circulating throughlarge nozzle permits the hole to erode on one side The drilling assembly is spudded to force the bit to follow thejetted hole After two to four feet of jetted hole is obtained drilling is commenced

After jetting, a single shot survey is run to determine the dog-leg severity of the hole Reaming may be necessary

if the dog-leg obtained is more than desired

D The Rebel Tool

The Rebel Tool is designed to prevent and correct lateral drift See Figure P2-11

Figure P2-11 Rebel Tool

Without orientation, the tool counteracts the bit's tendency to walk either left or right

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With a Rebel Tool, Drilling can continue under normal or near-normal weight loads, rotary speeds and pump

pressures The drift angle can be maintained as effectively with the Rebel Tool as with ordinary drill collar andstabilizer drilling assemblies

Mounted just above the bit, the Rebel Tool imparts a lateral shove to the sidewall by means of two opposing

paddles

The paddles are rigidly secured to a common shaft which is free to turn within a groove along the tool's body

As it rotates to the low side of a slant hole, the top paddle is forced by weight into a recess in the body of the tool.This extends the bottom paddle to shove against the sidewall in the direction desired down near the bit, wherethe effect is greatest

In cases where the Rebel Tool is used to correct lateral drift that already has occurred, slight overcompensation isrecommended before pulling the tool to resume normal drilling Several hundred feet of depth should be allowed toeffect the desired walk

To walk bit left: with left paddles (seen here in cross section from above, the bottom paddle kicks bit to the leftwhen extended by weight on its opposing member

VI Orientation Of Deflection Tools

Deflection tools may be oriented by many means, the most common of which are:

A Mule Shoe

A lug inside of a special sub is aligned with the bend or face of a deflection tool that is run into the hole with thedeflection tool A single-shot instrument is run into the hole inside of a protective case that has a stinger on thebottom that is helixed in a curving manner so that when helex curving engages the orientation lug inside of thespecial sub, the instrument is rotated so that the key slot on the stinger sets exactly on the lug A single-shot survey

is taken so that the direction of the key slot can be determined Orientation of the tool can then be completed

B Direct Method

North and South magnets are placed inside of a nonmagnetic drill collar in a position to align with a needle locatedinside of the single-shot instrument The compass unit is below the magnets and is not affected by the magnets.The needle pointing to the magnets is superimposed on a directional survey film disc When a survey is taken, thedirection of the deflection tool can then be found and the tool set

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C Surface Readout

Figure P2-12 Steering Tool

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This method of tool orientation is used in conjunction with a downhole mud motor in order to accurately measurereactive torque generated by the motor while drilling A mule-shoe orienting sleeve is run in the mud motor drillingassembly A probe is run on electrical conductor wireline through the drill pipe and seated in the mule-shoe sleeve.Data from downhole is transmitted continuously via the wireline to the surface readout equipment located on therig floor and in the wireline unit The readout unit, depending on the brand used, can deliver one or all of the

following typos of information:

1 Tool Face Direction

2 High Side of the Hole

3 Hole Direction

4 Drift Angle

5 Bottom Hole Temperature

6 Magnetic Information

The kelly is not used while drilling with a surface read out unit in the hole Instead, a circulating head is assembled

on top of a joint or more of drill pipe

VII Principles Of Directional Drilling Stabilization

A Building Angle

A Downhole Motor or Jet Bit assembly is usually used to start the deflection in a directional hole and to establishthe deflection towards the bottom hole target After the drift angle has approached approximately 5 degrees to 8degrees, the deflection tool may be replaced with a drilling assembly as shown in Figure P2-13

Figure P2-13 Maximum Angle Building Assemblies

However, if jetting has been the method of initial control, the assembly shown probably has been the one used inconjunction with the orientable jet bit In this event, drilling continues without requiring a trip

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Building angle with a limber drilling assembly is based upon the fulcrum principle The near bit stabilizer, properlyspaced above the bit creates a pivot point wherein the bending drill collars force the top of the stabilizer to the lowside of the hole and causes a lateral force at the bit in the opposite direction or high side of the hole This

causes the bit to increase drift angle

B Controlling Rate of Angle Increase

Controlling the rate of angle increase is imperative if fatigue to drill pipe and drill collars is to be avoided This can

be accomplished with the angle building drilling assembly in one of several ways:

1 Reducing the O.D of the stabilizer blades or cutters

2 Changing the fulcrum point of the stabilizer

3 Placing the stabilizer closer together in the drilling assembly

4 Increasing the stiffness of the drill collars

5 Changing bit weight, rotary speed and pump pressure

Type of stabilizers depend upon the formation in which they are to be used, (Figure P2-14)

Figure P2-14 Minimum Angle Building Assemblies

Stabilizers are bearings placed on a drilling shaft (drill collars) and in general practice, the placing of bearings(stabilizers) closer together on a shaft (drill collar) stiffens the shaft Therefore, by carefully controlling the spanbetween the stabilizers, the directional driller can control the rate of deflection angle movement reasonably well

C Maintaining Angle

When the deflection angle has reached the desired amount, the maximum or minimum angle building assembliesmay be replaced with a stiff bottom hole assembly that will permit optimum drilling operations to continue in thedirectional hole Usually, these assemblies are custom designed at the well site by the directional driller, based uponknown experiences in the general area

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Figures P15a, P-15b and P-15c show the progressive stiffness of the drilling assembly, but Figure P-15c is by nomeans the stiffest bottom hole assembly used

Figure P2-15 Packed Hole Assemblies

The use of square or triangle drill collars, multiple welded or integral blade stabilizers may be required, or rollerreamers in conjunction with any appropriate mixture of stabilizer typos in order to "lock" the hole on course and toallow maximum penetration rates to be obtained

If an extremely stiff bottom hole assembly is desired to be run in a directional hole after a large amount of trolled hole has been drilled, then a Set of drilling jars should be used on the reaming trip in to hole with the stiffassembly to prevent sledging the string in tight portions of the hole It may be necessary to lead the assembly intothe hole with a pilot reamer to prevent side tracking the deviated portion of the hole

con-D Dropping Angle

In Type II directional well patterns it is necessary to allow the drift angle to straighten back to vertical or nearvertical By controlling the distance between the bit and first stabilizer, (usually 60') and the stiffness of the drillcollars, the rate of angle descent can be controlled Since gravity and the weight of the drill collars apply a lateralforce at the bit on the low side of the hole that is helped by the pivot point at the first stabilizer above the bit,straightening usually occurs

E Care of Stabilizers

The bottom 120' of a drilling assembly is the critical portion for controlling a directional well The stabilizers used inthis area should be full gauge to 1/16" under unless undergauge stabilizers are required to hold angle Undersizedtools should be moved up higher in drill collar assembly or replaced with full gauge tools

Additional information on the subject of stabilization is contained in the Straight Hole Section of the manual

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VIII Dog-leg Severities

A Drill Pipe Fatigue

Changes in hole curvature are often referred to as dog-legs The severity of a dog-leg is determined by theaverage changes in angle and/or direction of the distance this change occurs For example, if there is a 5 degreechange in angle (no direction change) over 100 feet of hole, the dog-leg severity is 5 degrees per 100 feet Ifdirectional survey information is known, Figure 16 can be used to determine dog-leg severity

Figure P2-16 Dog-Leg Severity Chart

Notes for Fig P2-16 - EXAMPLE:

STATION 1: 2910 FT DEPTH, 3° INCLINATION N11°E

STATION 2: 3000 FT DEPTH, 5° INCLINATION N23°E

A) CHANGE OF HORIZONTAL ANGLE: 23° - 11° = 12°

B) AVERAGE HOLE INCLINATION: (3 + 5)/2 = 4°

C) CHANGE IN INCLINATION: 5° - 3° = 2°

E) SURVEY INTERVAL: 3000' - 2910' = 90'

F) DOG-LEG SEVERITY = 2.5°

Courtesy of Sii Drilco, ARTHUR LUBINSKI

"How To Determine Hole Curvature" Petroleum Engineer, February 1957

Until a dog-leg reaches some threshold value, no drill stem fatigue damage occurs This threshold value is calledCritical Dog-leg The critical dog-leg is dependent upon the dimensions (size) and metallurgy of the drill pipe anddrill pipe tension (pull) in the dog-leg

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The charts in Figures P-17 through 20, constructed for most of the common size and type drill pipe, can be used todetermine the Critical Dog-leg or the Maximum SAFE DOG-LEG limit that should not cause drill pipe fatiguedamage

The charts in Figure P-17 and Figure P-18 are identical Both are for Grade E drill pipe

Figure P2-17 Maximum Safe Dog-leg Limits Grade E Drill Pipe

Notes for Fig P2-17 - EXAMPLE: Dogleg @ 3000 ft

(A) proposed mud weight at td 12,000 ft = 16.0 lb/gal

(B) 4-1/2'' 16.60 ppf drill pipe (17.8 ppf actual weight)

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Figure P2-19 Maximum Safe Dog-Leg Limits, S-135 DP,

Ex 1 Notes for Fig P2-19 - EXAMPLE

Example: (dog-leg at 3,000 ft.)

(A) proposed mud weight at TD 18,000 ft = 18.0 ppg

(B) 4-1/2'' 16.60 ppf S-135 drill pipe (18.8 ppf actual weight)

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Figure P2-20 Maximum Safe Dog-Leg Limits, S-135 DP,

Notes for Fig P2-19 - EXAMPLE

Example: (dog-leg at 3,000 ft.)

(A) proposed mud weight at TD 18,000 ft = 18.0 ppg

(B) 4-1/2'' 16.60 ppf S-135 drill pipe (18.8 ppf actual weight)

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From a practical standpoint regarding drilling the well and designing the bottomhole assembly (BHA), the mostsignificant difference between the two is the ability or inability to rotate the BHA and the drill stem withoutexceeding the endurance limits of the components

This factor has a major impact on almost every aspect of BHA design, well profile selection and a host of otherdrilling parameters such as mud properties and the hydraulics program

From a design and operations viewpoint, it makes a great deal of sense to consider long-radius wells as thosewhere drill stem rotation is feasible at all times Medium-radius wells, on the other hand, must deal with the notinsignificant burden of being unable to rotate the BHA while drilling the build section of the well

2 Long-Radius Assemblies

Long-radius wells usually are drilled with steerable motors such as the one shown in Figure P3-1A

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An unexpected decrease in build rate can be compensated for by increasing the percentage of sliding vs rotatingtime

Conversely, should the assembly build at a higher than expected rate, the operator has the option of increasing thepercentage of rotating time thereby reducing the effective build rate

Assuming that the assembly has been properly designed initially, the operator could most likely adapt to changinglithologies, hole enlargement, etc., as they occur

Such an assembly could produce a smooth curve profile without the need for a tangent section, like the one shown

in Figure P3-5A

Figure P3-5A Medium-Radius Well Profile

However, should a tangent section be desired, either to increase the safety margin over and above the 33 %intrinsic to the assembly or simply to increase well departure, then the proven ability of the steerable assembly torotate and maintain angle assures that a trip simply to change-out the BHA is unnecessary

Strictly from a trajectory control standpoint, the ability to drill to a 90 degree inclination with such a system is nomore difficult than is controlling a conventional directional well

3 Medium-Radius Assemblies

Once the ability to rotate the drillstring is forfeited, the design approach for the bottomhole assembly and the wellprofile itself changes significantly More emphasis must be placed on accurate trajectory prediction The inability torotate without exceeding the endurance limits of the drill stem may also place greater demands on the hydraulicsand mud programs

The agitation caused by rotation of the string is a very significant factor in high-angle/high-curvature hole cleaningand in preventing the formation of a cuttings bed Without this mechanical agitation, the operator must rely solely

on hydraulics and mud properties to remove cuttings from the wellbore

For now let us assume that the assembly is limited to the sliding mode only Medium-radius assemblies typically aredouble-bend assemblies specifically, a single-bend steerable motor in conjunction with a second bent memberaligned immediately above the motor Because of the potential for sticking, such assemblies are generally runwithout stabilization

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In the absence of rotation, stabilization below the bent motor housing serves no useful purpose and should beavoided

Figure P3-2A graphically illustrates a typical double-bend assembly

Figure P3-2A Medium-Radius Assembly

One of the most common misunderstandings concerning such double-bend configurations is that the bent sub isrequired to achieve the higher build rates This normally is not the case

Figure P3-3A compares a single-bend assembly to the same assembly which has a second bend added, a 1-1/2degree bent sub in this case

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Figure P3-4A Build-up vs Hole Enlargement

The relatively large bit offset produced by a bent sub/motor combination helps to maintain a constant lateral bitforce when hole enlargement occurs The result is a more uniform rate of build as hole diameter increases

The lateral force exerted on the bit by a single-bend stabilized assembly changes rapidly with hole enlargement Asmight be expected, the end result is often a less consistent build rate

Combining a bent housing motor and a bent sub provides an assembly that not only is less susceptible to holeenlargement (the bent sub effect), but one that can achieve medium-radius build rates (the bent-housing effect)

4 Medium-Radius Well Plan

When designing BHAs for medium-radius applications, much more emphasis must be placed on achieving able and uniform build rates This is simply because the medium-radius assembly does not have the intrinsic safetymargin of the long-radius steerable system

predict-A properly designed medium-radius assembly essentially has one build rate only It may increase slightly with moreweight-on-bit or with increased hole angle, or it may decrease somewhat with higher flow rate and accompanyinghole enlargement None of which, however, provides the operator with much flexibility to alter build rate withouttripping For this reason, medium-radius wells usually incorporate a tangent section into the well plan to help

compensate for build rate unpredictabilities Figure P3-5A shows such a profile

This tangent interval provides a vertical depth safety margin which is calculated with the formula: Cos (tangentsection angle) x (length of tangent section)

Certainly anyone drilling the first medium-radius well in a given location should seriously consider incorporating atangent section into the well plan in order to obtain as much of a safety margin as possible

In areas where geology is unpredictable, well profiles with tangent sections will be necessary

However, when planning an extended medium-radius drilling program in a field with predictable formation teristics, much can be gained by eliminating this section

charac-Inclusion of a tangent section not only may require two additional bit trips, it produces unnecessary stresses on themotor and other downhole components as the well is kicked-off for a second time at the end of the section

The ability to accurately predict the trajectory of a given BHA can provide considerable cost savings

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5 Performance Predictions

It was mentioned earlier that build rate is not the only determinant of tool configuration (i.e., single vs doublebend) It has been shown that in some formations drillability perpendicular to the bedding planes is greater thandrillability parallel to the bedding planes

The net effect of this formation anisotropy (crooked-hole tendency) from a trajectory prediction standpoint is thatthe build rate is influenced by the relative angle between wellbore inclination and formation dip

In moderately crooked-hole country this effect can add or subtract several degrees of build as the well angle buildsfrom vertical to horizontal

It can be a continuous effect if the wellbore inclination is changing consistently across a formation with a constantdip angle or it can be a more instantaneous effect if the dipping planes or formation type changes suddenly: Failure

to take such effects into account, particularly when coupled with other factors such as changing hole diameter, canhave serious repercussions These factors, and others, have always influenced wellbore drift and bit walk In mostcases, the long-radius profile is forgiving and allows ample opportunity for corrections should they even be neces-sary at all However, such is not the case with medium-radius wells

Figure P3-6A shows output from a typical trajectory prediction program simple enough to be run on a portablecomputer yet complex enough to provide an accurate prediction of BHA trajectory

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P-91

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The following parameters are taken into account: hole size and angle, formation dip, crooked-hole tendency offormation, bend configuration, stiffness of drillstring, mud weight, weight-on-bit and any BHA configuration.The solution, expressed in degrees/100 ft, is in the third column from the right Notice the significant differencebetween the three cases illustrated All three cases are for the same double-bend assembly run with 20,000 poundsweight-on-bit in a moderately crooked-hole formation Dip angle remains constant for all cases

Cases 1 and 2 represent the effect of hole angle change from 10 to 60 degrees inclination (fifth column from left)and Cases 2 and 3 represent the effect of hole enlargement Case 3 shows a 15% decrease in build rate with oneinch of hole enlargement Such programs are only as good as the quality of the input data Nevertheless, with evenminimal offset data, the results are surprisingly accurate

For combinations of hole angles and hole size, for 5inch, 19.5 lb/ft steel drill pipe in 15.5 ppg mud

B Proper Drill Stem Design

(Authors Denny Kerr And Sam Clayton)

1 Introduction

It is a reasonably straightforward process to design longradius bottomhole assemblies (BHAs) that can guide thedrill bit to horizontal and maintain hole angle for several thousand feet It is an equally direct process to design aBHA that will guide the drill bit to horizontal at very high rates of build (20 deg/100 ft or greater) These extendedhorizontal sections and high build rates, however, tend to produce significantly higher torque and drag loads on thedrill stem A competent drill design that can safety handle the increased axial and torsional loading is as significant

a problem as the design of the BHA itself

The following factors must be addressed when designing the drill stem for a horizontal well:

1) High build rates and long horizontal sections produce pick-up and torsional loads that can quickly exceed theoperating limits of standard-grade oilfield tubulars

2) The need to transmit axial load to the bit in the horizontal section often subjects heavy-weight drill pipe and, insome cases, standard drill pipe to compressive loading

3) The need for heavier drill stem components in the upper (vertical) section of the wellbore to overcome the axialeffects of friction while tripping in the hole and to provide adequate weight-on-bit while drilling

Designing a drill stem to overcome these problems requires the ability to accurately predict the tensile, torsionaland compressive loads at any point along the drill stem This capability will permit the following:

1) Placement of tubular components within a given drill stem such that the components within each section are notsubjected to mechanical loading that exceeds their design limitations

2) Placement of the appropriate components in the compressive portion of the drill stem that can transmit adequateaxial load (weight-on-bit) without buckling

3) Selection of a rig with sufficient capacity to rotate and hoist the drill stem

2 Weight-on-Bit

Drill collars are typically used near the bottom of the drill stem in conventional wells to provide weight-on-bit(WOB) and to ensure that the drill pipe above the collars always remains in tension Heavy weight drill pipe isused in conventional wells between the drill collars and standard drill pipe to provide additional weight and tofurther isolate the drill pipe from compressive loading In horizontal wells, however, placement of the drill collarsnear the bit cannot increase weight-on-bit Drill collars in the horizontal section increase torque, drag and thepotential for differential sticking

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For this reason, the only drill collars run in the horizontal section should be the non-magnetic collars required toisolate the survey instruments from magnetic interference The primary WOB component must be located in thevertical or near-vertical section of the drill stem Drill collars and / or additional heavy weight drill pipe are

"stacked" in the vertical section of the wellbore to provide weight to the bit The result is that the entire drill stembelow this section is subject to compressive loading This drillstring commonly referred to as a "reverse-tapered"string

Heavy weight drill pipe is typically run from the end of this weight-supplying section through the build portion of thewellbore to the horizontal section The inability of standard drill pipe to handle axial loading at lower angles hasbeen proved by Dawson and Pasley <1> (Figure P3-1B)

Note for Figure P3-1B: For combinations of hole angles and hole size, for 5" 19.5 ppf steel DP in 15.5 ppg mud.Heavy weight drill pipe typically is used through this area of the hole to avoid pipe buckling

3 Transmitting Adequate WOB

Perhaps the most significant design consideration is the selection of drill stem components for the horizontal sectionthat can safely transmit WOB from the upper "stacked" portion of the drill stem through to the horizontal section,while minimizing overall drill stem weight and the resulting higher pick-up loads

For short horizontal sections, heavy weight drill pipe generally is the optimum choice because it is designed forcompressive service and is capable of transmitting very high axial loads without buckling For example, a 5-inch(49 lb/ft) joint of heavy-weight drill pipe in a 8-1/2-inch hole is capable of transmitting in excess of 100,000 pounds

of weight to the bit without buckling, provided the hole is at or near horizontal

As the horizontal section is extended, the weight of the heavy-weight drill pipe may become a length limiting factorbecause the overall drill stem pickup load increases as the horizontal lengthens At some point, the use of standardgrade drill pipe must be considered as a means of minimizing overall pickup load

Dawson and Paslay also have shown that it is indeed practical to run drill pipe in compression in high angle wells.Figure P3-1A indicates that standard 5-inch (19.5 lb/ft) drill pipe can safely transmit in excess of 30,000 poundsweight-to-bit without buckling, provided the wellbore is at or near horizontal

Although there are cases where minimal buckling may be tolerated, in the interest of conservative drill stem design

it is assumed here that any buckling condition whatsoever should be avoided

4 Pick-Up Weights & Torsional Loads

The case study illustrates the fact that drill stem pick-up weights and torsional loads in horizontal wells oftenexceed the mechanical limits of standard-grade oilfield tubulars Even when this is not the case, these unusuallyhigh loads may justify the use of premium grade tubulars to provide safe operating margins based on an operator'sindividual requirements

Tables P3-1B and Table P3-2B, taken from the API RP7G, show tensile and torsional yield strengths for some of the more commonly used sizes of drill pipe It should be noted that these tables denote API Class 2 drill pipe which makes some allowance for minimal and uniform pipe wear

It is important to recognize that, given current oilfield economy, many rigs may not have API Class 2, standardtubulars It is recommended that all drill pipe to be used in horizontal wells be carefully re-inspected

5 Case Study

The following case study illustrates a typical drill stem for a medium-radius well with an extended horizontal

section (Figure P3-2B)

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TABLE P3-2B Tensile Yield Strength - API Class 2

Further down the drill stem, as incremental pick-up load decreases, Schedule 95 pipe may be used and drill stemintegrity is maintained Drill collars are stacked in the vertical section to provide weight-on-bit Heavy-weight drillpipe is used through the build section of the well to transmit weight to the bit and to ensure that buckling does notoccur

Figure P3-1B clearly shows that the standard 5 inch (19.5 lb/ft) drill pipe used in the horizontal section is adequate

to transmit the required 30,000 pounds weight-on-bit without buckling

6 Use of Top Drive

One obvious advantage of using a drilling rig equipped with a top drive can be observed in the difference betweenthe maximum pick-up load of 448,000 pounds and the rotating off-bottom load of 211,000 pounds

The ability to rotate while tripping negates the axial effects of friction which significantly reduces the hoistingrequirements of the drilling rig, and allows the operator to use a less expensive grade of drill pipe

7 Non-Magnetic HW Drill pipe

There has been some debate concerning the substitution of non-magnetic, heavy-weight drill pipe for the required

6090 foot of non-mag drill collars The output from the torque/drag computer model reveals the effects of such asubstitution to be insignificant

Unless the potential for differential sticking is severe, the use of expensive, nonstandard equipment is a waste ofoperator's funds

8 Aluminum Drill Pipe

The use of aluminum drill pipe is another highly discussed issue Aluminum drill pipe buckles at approximately halfthe compressive load of its steel counterpart and is generally unacceptable for transmitting adequate weight to thebit This severely limits its use in the lower section of the drillstring

To offset the fact that aluminum has a yield strength that is approximately 77% that of steel, a joint of standardaluminum pipe must have a 30% larger cross-sectional area to provide tensile strength comparable to Schedule Edrill pipe

For our example well, aluminum could not be used for the same reason that Schedule E drill pipe could not be used:inadequate tensile strength

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In instances where use of aluminum drill pipe is feasible from a tensile strength standpoint, the operator mustsacrifice wellbore hydraulics efficiency Even wells as demanding as the example well can be safety designed anddrilled using standard-grade oilfield tubulars

9 Reference:

Dawson, R and Paslay, P.R., "Drill Pipe Buckling in Inclined Holes", SPE 11167 presented at 1982 Fall TechnicalConference and Exhibition, New Orleans, September 26-29

C Factors Determining Optimum Well Profiles

(Authors Denny Kerr And Don Swain)

1 Introduction

There are many factors that come into play when determining the optimum well profile for a specific horizontalwell

Determinants of the well profile include:

1) reservoir applications (amount of horizontal extension required);

2) location, thickness and dip of target interval;

3) formation characteristics and casing requirements;

4) formation friction coefficients;

5) degree of geological certainty (or uncertainty);

6) well spacing regulations and requirements;

7) completion methods;

8) weight-on-bit requirements;

9) local availability of equipment;

10) rig capacity; and

11) minimized measured depth

It has been shown that relatively minor changes in the build profiles of extended-reach wells can have a significantimpact on their torque/drag values and the corresponding drill stem loads For wells having target true verticaldepths (TVDs) in excess of 10,000 ft and horizontal displacements in excess of 5,000 - 8,000 ft, optimizing thespecific build profile can have a tremendous effect on the torque/drag values of the well However, these wells arenot representative of the typical horizontal well being drilled today

Today's typical horizontal well has a target TVD of 10,000 ft or less and a total displacement of less than 5,000 ft.This article will demonstrate that, for the most part, the typical horizontal well can be designed independent of agiven build rate, based on practical considerations such as well spacing requirements and minimizing drilling byutilizing locally available equipment

2 Reservoir Applications

The length of horizontal section required generally has less effect on the well profile and build rate than one mightthink Horizontal sections of at least 5,000 ft are possible with both long and medium-radius wells Medium-radiuswells with horizontal sections in excess of 3,000 ft have been drilled, and there is no reason from a drill stem designstandpoint that the horizontal sections in medium-radius wells cannot be extended to at least 5,000 ft using standard

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tubulars

Both target TVD and displacement from the original wellbore or surface location can have major effects on thebasic build profile Lease line restrictions frequently dictate a high build rate in order to minimize well offset at thereservoir entry point and thereby maximize the horizontal section length Medium radius wells with their shorterdisplacement are optimal choices here Targets with a thickness of 12 ft or less may require placement of a sectionwith a reduced build rate in the lower well The effect is similar to adding a tangent section at the very bottom ofthe build Exactly where this lower build rate starts and how much vertical section it must cover is a function offormation consistency, operational experience and the service company's confidence in their build assembly.Execution of a perfect 16.0 degree/100 ft build from a 60 degree to horizontal in order to "bull's-eye" a 6 ft thickpay zone requires an impossible build rate predictability, simply from a formation inconsistency standpoint Target-ing a medium-radius well into a thin formation is much easier with a flexible steerable assembly

It is the formation dip, of course, that determines the final inclination of the wellbore

Extreme formation inconsistency can make drilling a medium radius well virtually impossible Severe hole ment can limit even the most radical build assemblies to build rates of 5-6 degrees/100 ft

enlarge-The vertical depth between target TVD and existing intermediate casing may dictate use of a high rate of build.While important for extended-reach wells, high friction coefficients generally have little restrictive effect over therelatively short, high-angle course lengths of the typical horizontal well The case study presented at the end of thisarticle uses relatively high friction coefficients and shows little or no restrictive effects

Lower build rates produce higher displacements to the target, which can add an element of uncertainty from ageological standpoint Where formation discontinuities or erratic dipping planes are a problem, a practical solutionfor a medium-radius well would be to drill a pilot hole as an extension of the tangent Figure P3-1C shows such aprofile

Once the exact location of the target is determined with the pilot hole the well can be plugged back and tracked to horizontal

side-Well spacing regulations and requirements, which vary from well to well and state to state can be complex, andalso play an important role in choosing the well profile

It is beyond the scope of this article to discuss completion methods at length but they obviously are a prime eration when planning the well The vast majority of horizontal wells drilled to date have either been longradiuswells that were completed by essentially conventional means or medium-radius wells that were drilled throughcompetent limestone or dolomite formations and then were completed with slotted liners

consid-Weight-on-bit (WOB) requirements can have a significant impact on long, extended-reach wells, but generally arenon-restrictive in typical horizontal wells

High WOB may require running heavy-weight, or at least heavier drill pipe in the horizontal section to avoid

buckling This increases the torque and drag forces throughout the well Conventional horizontal wells generally donot have a problem with WOB requirements

From a practical standpoint, local availability of equipment and rig capacity are two of the most important designconsiderations when planning a conventional horizontal well Typical horizontal wells generally do not require anyspecialized equipment (i.e., aluminum, wear-knotted, or non-magnetic heavy-weight pipe)

As with conventional drilling in a tight market based on low oil prices, making horizontal drilling a widespreadpractice depends upon strict cost controls The cost of a horizontal well escalates rapidly when high-priced, specialequipment is specified Experience has shown Smith that 99 % of the horizontal wells drilled to date could havebeen designed around locally available rigs and tubulars

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As shown in Figure P3-1C, several of the widely-used, long-radius well profiles result in measured depths that aremany hundred feet longer than medium-radius wells that accomplish the same thing

Figure P3-1C depicts three long-radius horizontal well profiles as well as a typical medium-radius profile

Should a long-radius well be chosen for completion reasons, the additional measured depth may be necessary But

it should be noted that medium-radius wells often offer a less expensive option in terms of, both minimized sured depth and lower overall drilling torques, drill stem loads, and the resulting lower repair and maintenance cost

mea-on the tubulars

Each profile had 1500 ft horizontal sections at 7,000 ft TVD Based on an 8-1/2 inch hole diameter and a on-bit design limitation of 30,000 pounds, all four profiles carried 800 ft of 5 inch 25.6 lb/ft, drill pipe in the horizon-tal section and each steerable bottomhole assembly was 140 ft long with 6.25 inch OD Mud weight was 9.2pounds/gal

weight-One design restriction was that drill collars would not be carried into the inclined hole sections As a result, only themedium-radius assembly used drill collars to provide weight-on-bit (Table P3-1C)

In the three long-radius wells, WOB was provided exclusively by the heavy-weight drill pipe While drilling with30,000 pounds WOB, all four profiles had 15,000 pounds of additional weight available above the neutral point inthe form of drill collars or the heavy-weight drill pipe

Table P3-1C and Table P3-2C show pertinent drillstem data and torque/drag values

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While rotating off bottom however, the drillstring is in tension through a portion of the dog-leg and some fatiguedamage could be anticipated Our experience shows that this has not been a problem to date; however, this may bedue to the fact that there simply are not any drillstrings around that have been subjected to any significant number

of fatigue cycles in high build rate wells If in time fatigue failure should prove to be a significant problem, the use

of steel drill pipe protectors would almost certainly prove to be a reasonably inexpensive solution <3>

3) Lubinski, A., and William S.: "Usefulness of Steel or Rubber drill Pipe Protectors", SPE Paper 11381 presented

at the 1983 IADC/SPE Conference, New Orleans, LA, February 20-23, 1983

D Four Factors That Affect Fatigue Damage

The first three articles in this series illustrated the feasibility of designing and drilling horizontal wells using standardoilfield tubulars which are readily available and relatively inexpensive

The most conventional hole sizes, i.e., 6-1/8 to 9-7/8 inch horizontal wells can be drilled to measured depths inexcess of 15,000 ft to vertical depths in excess of 10,000 ft and in horizontal sections in excess of 3,000 ft whilestill using standard grades and weights of tubulars This is true for both medium-radius and long-radius profiles

As an industry, we can design highly flexible, steerable bottom-hole assemblies that will not produce excessivetorque and drag in the horizontal section We can also design lightweight portions of the drill stem for the horizontalsection that are more than capable of transmitting adequate weight to the bit In doing both of these things, we canreduce the torsional and tensile requirements in the upper portion of the drill stem to the point where standardcomponents can also be used there

The experience of Smith International alone of 35 horizontal wells to date has proven this At no time during thedrilling of any of these 35 wells were drill stem components subjected to stresses outside of their design limitationswith one exception The exception? drill stem fatigue associated with reaming and rotating off-bottom through theextreme doglegs associated with medium-radius wells To date, however, Smith has not experienced any fatiguefailures or identifiable fatigue damage

With this in mind, let us examine the four factors that determine the amount of fatigue damage as they relate towellbores in general and to horizontal wellbores in particular These four factors are:

1) Tensile load in the pipe at the dogleg,

2) Severity of the dogleg,

3) Number of rotational cycles experienced in the dogleg, and

4) Mechanical properties of the pipe itself

The tensile load in the pipe at the dogleg, (i.e., at the kickoff point), generally tends to be less than for most dard directional wellbores the reason for this is that the well is usually built to 90 degree inclination immediatelyfollowing kick-off

stan-The faster this build takes place, the less distance is available below the kick-off point for suspended members toproduce a tensile load while drilling

With medium-radius wells, there is typically no tensile load while drilling

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It is important to remember that there are collars stacked in the vertical section of the hole above the kick-offpoint Everything below these collars is in compression Tensile load may exist at the kick-off point of the medium-radius well while rotating off bottom and while reaming Although it is certainly true that this tensile load is associ-ated with extreme doglegs in medium-radius wells, the tensile load can be very great Medium-radius wells build tohorizontal very quickly and have little vertical section distance below this high dogleg in which tensile loads candevelop Long radius wells may have higher tensile loads than their medium-radius counterparts while drilling orwhile rotating off bottom, but, by definition, these loads are associated with much lower doglegs

In October of 1960, Arthur Lubinski published a significant work which outlined the maximum permissible doglegs

in rotary boreholes <2> A great deal of the practical work done in the paper was based on the fact that themaximum reversed bending stress which will cause no fatigue failure in a joint of drill pipe depends on the averagetensile stress to which the pipe is subjected One of the most useful aspects of the paper was a dogleg severityversus tension curve for 4-1/2 inch Grade E drill pipe the end result of Lubinski's work can be found in Section 6

of the API Recommended Practice RP7G <1> in the form of dogleg severity versus tension curves for variousgrades and sizes of drill pipe

The set of curves illustrated in Figure P3-1D was derived from Lubinski's work for Range 2 (30 ft) joints of drillpipe

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Figure P3-1D3 Dog-Leg Severity vs Tensile Curves, HW-DP

These curves plot the allowable tensile load for drill pipe versus the dogleg experienced by the drill pipe at thatpoint The equations from which these curves were derived are taken directly from Section 6 of the API RP7G,specifically Equations 6.1 through 6.6

Across the range of dogleg severities shown in these curves, standard Grade E drill pipe is shown to be leastresistant to fatigue damage Schedule 135 drill pipe offers only modest improvements over Grade E drill pipe.However, Hevi-Wate* drill pipe, with its center upset, offers significant improvements over standard drill pipe.The last curve is for the pipe that is commonly referred to as "compressive service drill pipe", (i.e., S-135 drill pipewith three additional upsets in addition to the tool joint upsets) This pipe was originally patented by Arco to

eliminate fatigue damage in drill pipe rotating at fairly low doglegs but under high tensile loads In this application, it

is highly effective

Compressive service drill pipe also appeared the following year in an Arco medium-radius drilling methods patentfor reducing fatigue in higher doglegs, (i.g., those encountered in medium-radius drilling) The graphs show that thispipe does offer some additional fatigue resistance over standard Hevi-Wate

Consider: A typical medium-radius well with a 20 degree/100 ft build rate and a 200 ft tangent section placedbetween the upper and lower builds at an average angle of 40 degrees Assume that this well also has a 1,500 fthorizontal section, a true vertical depth of 7,000 ft, and a kick-off point of 6,561 ft

This well would be quite similar to Profile "D" from Part 3 of this series While on bottom and drilling, this profilewould be expected to have a minimum compressive load of 10,300 pounds at the top of the build In this case thedrill pipe in the build section would not be subject to fatigue while drilling

Having the drill stem in compression through the build while drilling is typical of all medium-radius wells However,while rotating off bottom, we can predict a "worst case" tensile load of approximately 18,700 pounds in that portion

of the drill stem rotating in the top of the dogleg This corresponds to Point "A" on the graph shown in Figure D2 (figure not found - HAK)

P3-Based on this graph, we could eventually expect fatigue damage with any of these drill stem components

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Yet, the fact remains that Hevi-Wate and compressive service drill pipe have indeed been rotated in higher

doglegs, (e.g., doglegs of greater than 22 degrees/100 ft), and under more tension than that predicted withoutshowing any signs of fatigue damage This is possibly due to the following reasons:

1) Tensile loading is always small while rotating off bottom in medium-radius wells; thus, it has a very minor effect

on reducing the life of the member

2) Tensile loading in medium-radius wells exists only while rotating off bottom or while reaming It does not existwhile drilling

3) While reaming, tensile loading is either significantly reduced or drill pipe in this upper portion of the build isactually in compression due to down-drag from the drill stem and stabilizers as well as resistance at the bit

4) While reaming, no single joint of drill pipe is in the danger zone for any significant amount of time

5) The tubulars in this section during the build-up portion of the medium-radius well are not subject to rotation;therefore, they cannot experience fatigue damage

6) The tubulars in this section during the horizontal portion of the wellbore (while the string is constantly rotating)never undergo a significant number of fatigue cycles for two reasons:

a) The tensile load quickly drops as the component in question is moved into a higher angle section of wellbore.This moves the component into a region of reduced tension or actually into compression and out of the danger zonequickly

b) Whether reaming or rotating off bottom, the drill stem does not normally turn at a speed greater than 25 to 30rpm's The drill stem is rotated only to negate the effect of the bent, steerable motor Bit rpm comes primarily fromthe downhole motor

NOTE: This last point makes a strong argument for running steerable motors in the horizontal section versus rotarydrilling to avoid drill pipe fatigue

As medium-radius drilling becomes more popular, drilling contractors and operators alike should be aware of thepotential for fatigue damage to their drill stem as a result of medium-radius drilling For the reasons given above, it

is unlikely that it will become a serious problem, but it always pays to be vigilant

Let's examine the bottomhole assemblies used in three individual cases In the first example, the horizontal sectionwas thin and extended In the second example, the horizontal section followed erratically dipping pay zones in anarea of geologic uncertainty

3) H.M Rollings, "Drill Pipe Fatigue Failure", Oil & Gas Journal, April 18, 1986

E Directional Control In The Horizontal Section

1 Introduction

A significant percentage of horizontal projects around the world are drilled through pay zones that are less than 12

ft thick

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The degree of economic success of such wells may be directly proportional to the amount of time that the operator

is able to stay in the pay zone Modem steerable PDM's make this kind of precise control possible

At times, a well plan demands a tremendous amount of flexibility and adaptability from the bottom hole assembly.For example:

1) When one well intersects multiple pay zones, e.g., where the assembly is required to build or to drop to reenter azone after crossing a fault;

2) When pay zones which dip erratically must be followed; or

3) When the ability to adapt to unexpected changes in lithology is important

In each of these three cases, the degree of flexibility and adaptability that the bottomhole assembly provides iscritical However, there are also horizontal applications where the pay zone is particularly thick or where longextensions are not required

In these cases, it may be preferable to drill the horizontal section with standard rotary assemblies

In the third example, the horizontal section was drilled with a standard rotary assembly

2 Case 1: An Extended Thin Horizontal Section

The 1,270 ft horizontal section was drilled off the coast of Western Australia in a fine-to-medium grain sandstonereservoir The target was a rectangle 6.56 ft high and 32.8 It wide Extremely fine control was required in this 25

ft thick oil zone to maintain optimal distance from the gas-oil and the oil-water contacts

Figure P3-1E illustrates the end section of the target relative to the reservoir

Figure P3-1E End Section of Target

Figure P3-2E is a vertical section plot of the actual wellbore

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Figure P3-3E What the Records Show

TABLE P3-1E BHA Used in Horizontal Extension

TABLE P3-2E Steerable BHA Used

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TABLE P3-3E Rotating BHA Builds from 85 to 93.5 degrees

This was accomplished by sliding 14 ft for every stand of drill pipe Because the assembly exhibited a slight buildtendency, the oriented corrections were accomplished by rolling the steerable PDM upside down and correcting itdown to the proposed well path From a practical standpoint, the ability to maintain the bit within a thin horizontalsection is limited primarily by the distance of the inclination measurement from the bit

The closer the inclinometers in the MWD tool are to the bit, the less lag time there is from the time the DirectionalDriller makes a course correction to the time he is able to evaluate the results of the correction

Since maintaining the wellbore within such a thin section is nothing more than a series of short corrections spersed between rotating time, the need to minimize this lag time is obvious Existing PDM and MWD tool con-figurations will normally result in the inclinometers being 40+ ft behind the bit This is a limitation when controlling awellbore through a thin horizontal section

inter-3 Case 2: Following Erratically Dipping Pay Zones and/or Reacting to Geologic tainty

Uncer-The 1,401 ft horizontal section was drilled in the Central United States in a fractured carbonate formation Uncer-Thehorizontal well was sidetracked from a vertical pilot well

Dipmeter log results indicated erratic dipping planes and directions through the intervals above the pay zone Thepay zone itself was 35-45 ft thick at a true vertical depth in excess of 9,800 ft

A medium-radius well was chosen, in part, to minimize the offset distance from the pilot well to reduce the risks ofgeologic uncertainty An MWD tool with a real time focused gamma-ray was run to provide correlation with thepilot well and to assist in controlling the horizontal section

The horizontal section (see Figure P3-1E) was a series of drops, followed by builds back to horizontal, followed bydrops

The steerable assembly followed a pay zone that was dipping down and away from the pilot well in a somewhatunpredictable manner The bottomhole assembly used to drill this 8-3/4 inch hole is shown in Table P3-2E

While an adequate amount of pay zone was intersected, the task was made more difficult by the distance of thefocused gamma-ray tool from the bit Even when the ROP indicated that the bit had exited the pay zone, thefocused gamma-ray was too far from the bit to assist in decision making This was especially true when the

change in dip was abrupt

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The question then became: Did we drill out the top of the formation or the bottom? Precious distance is lost as thefocused gamma-ray tool must now drill ahead 40-60 ft to determine whether the assembly exited the top or thebottom of the formation Steerable PDM assemblies do make drilling such wells economical, but this situationwould have been greatly improved if the bit-to-sensor distance could have been shortened considerably

4 Case 3: Horizontal Section Drilled with Standard Rotary Assembly

The 286 ft horizontal section was drilled on Alaska's North Slope with a standard rotary assembly

The relatively thick pay zones in the area do not require 57 ft directional control Similarly, favorable reservoirporosity and permeability do not dictate lengthy horizontal sections

The primary concerns here were twofold First, coning problems had to be reduced; and second, the recoveryrates had to be increased by extending contact with the pay zone

The true vertical depth of this 8-1/2 inch wellbore was 8,700 ft The horizontal displacement of the horizontalsection was in excess of 6,800 ft The horizontal displacement of the horizontal section was in excess of 6,800 ft.The final build from 65 degrees inclination to horizontal was made with a rotary assembly (no steerable PDM).The bottomhole assembly used here (see Table P3-3E) produced a smooth build to 93.5 degrees inclination

A portion of the actual survey results are shown in Table P3-4E

TABLE P3-4E Partial Results of a Survey

Note: the well has no true horizontal section The assembly builds right through horizontal to a maximum inclination

of 93.5 degrees (and even greater in some cases)

This particular method was popularized by British Petroleum and Arco Alaska, Inc and is routinely used today.Any formation that is thicker than 40 ft or that docs not require a lengthy horizontal extension to be economicallyfeasible is a potential candidate for drilling with a rotary assembly Consider the following "rules of thumb" whenswitching from drilling with a steerable PDM to drilling with a basic rotary assembly:

1 The potential for casing wear will increase because of the higher RPM of the rotary assembly

Remember: Steerable PDM's do not rotate in the sliding mode; nor generally faster than 25-35 RPM at thesurface while rotary drilling

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2 The increased number of rotary cycles increases the potential for drill stem fatigue in some medium-radiuswells

3 The rate of penetration in many fixed-head bit applications will increase significantly when a PDM is used as aresult of the higher bit RPM provided by the motor This is frequently enough to offset the additional cost of themotor

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