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Provisory - 06 Dec 96 Confidential Directional Drilling

Directional Drilling Training Manual

Section 13 - Drilling Problems

Document Type UOP Template (Word 6 PC)

Software Microsoft Word 6.0 for Windows NT

Source File DDTM_13.DOC

Other Source File TM.DOT

Author Mike Smith

Author info Anadrill Technique

200 Gillingham Lane

Sugar Land TX 77478-3136

Tel: + 1 281 285 8859

Fax: + 1 281 285 8290/4155

email: [email protected]

Review & approval

Revision History 05 Dec 96 2nd Revision

06-Dec-96 Final review and approval MJS

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Table of Contents

Provisory - 07 Dec 96 Confidential Directional Drilling 13-i

13 Drilling Problems Page

13.1AN OVERVIEW ................................................................................................................13-1

13.1.1 Differential Sticking .............................................................................................13-2

13.1.1.1 Warning Signs.............................................................................................13-5

13.1.1.2 Stuck Pipe Identification.............................................................................13-5

13.1.1.3 Preventive Actions ......................................................................................13-6

13.1.1.4 Rig Site Preparation ....................................................................................13-6

13.1.2 Borehole Deterioration .........................................................................................13-6

13.1.2.1 Warning Signs.............................................................................................13-8



13.1.3 Dog Legs and Key Seats.......................................................................................13-8

13.1.3.1 High Friction Factors While Drilling and Tripping ....................................13-9

13.1.3.2 Warning Signs.............................................................................................13-9


13.1.4 Key Seats ..............................................................................................................13-9

13.1.4.1 Warning Signs.............................................................................................13-10



13.1.4.4 Rig Site Preparation ....................................................................................13-11

13.1.5 Drill String Failures Due to Excessive Reverse Bending.....................................13-11


13.1.6 Equipment Compatibility......................................................................................13-12


13.1.7 Borehole Stability .................................................................................................13-12

List of Figures Page

Figure 13-1 Differential sticking............................................................................................ 13-3

Figure 13-2 Development of filter cake ................................................................................. 13-3

Figure 13-3 Effect of drill solids on filter cake...................................................................... 13-4

Figure 13-4 Filter cake bridging............................................................................................. 13-4

Figure 13-5 Erosion of filter cake .......................................................................................... 13-5

Figure 13-6 Effect of hole deviation & mud weight on borehole stability ............................ 13-7

Figure 13-7 Development of key seats................................................................................. 13-10

Figure 13-8 Key seat wiper and string reamer. .................................................................... 13-11

List of Tables Page

No list of figures.

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Drilling Problems

Provisory - 07 Dec 96 Confidential Directional Drilling 13-1

13 Drilling Problems

About this chapter

The development of new technologies in the past 10 years, like the MWD systems forreal-time surveying, steerable systems for an effective control of trajectory, PDC bits for

efficient drilling of long sections, mud and hydraulic systems for improved control of

hole cleaning and borehole stability, etc. have transformed directional drilling into a

common practice.

There are a few serious problems which may arise during the course of drilling a

directional well. The probability of certain drilling problems arising (e.g. differential

sticking) is increased by virtue of the well being deviated. The causes and implications of

differential sticking are discussed here, as well as solutions and possible preventive

measures. This is very relevant to the DD, particularly in areas which are prone to

differential sticking.

Dog legs and key seats are discussed here in detail. As mentioned elsewhere in thismanual, it is the DDs responsibility to ascertain the clients limit on dog leg severity at

the beginning of the project. The consequences of high dog leg severity at a shallow

depth often do not become apparent until much deeper in the well.

Problems caused by borehole instability due to poor hydraulics and mud conditioning are

outlined. Increases in Drag, particularly when drilling with a PDM, directly concern the

DD. In high-angle wells, it often becomes very difficult to "slide".

Objectives of this Chapter

On completing this chapter the directional driller should be able to do the following

exercises:

1. Describe the main causes of differential sticking.

2. Explain how the API Filtrate (Water Loss) influences the chances of getting

differentially stuck.

3. Describe the precautions the DD should take or recommend when about to drill in an

area known for differential sticking.

4. Explain why the chances of borehole instability are influenced by hole inclination.

5. List the drilling (and other) problems arising from high dog leg severity in a deviated

well.

6. Explain what the DD should do if his survey indicates an unacceptably-high dog leg

severity in the interval just drilled.

13.1 An Overview

The development of new technologies in the 80s, like the MWD systems for real-time

surveying, steerable systems for an effective control of trajectory, PDC bits for efficient

drilling of long sections, mud and hydraulic systems for improved control of hole

cleaning and borehole stability, etc. have transformed directional drilling into a common

practice.

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But, if we compare the performance and drilling conditions of vertical and directional

wells, it is possible to identify some particular problems related to deviated boreholes. In

this chapter we analyze the most common directional drilling problems and possible

solutions.

13.1.1 Differential Sticking

Differential pressure sticking occurs only across a permeable zone, such as sand. One or

a combination of the following mechanisms will be responsible for sticking:

Pipe sticking occurs when part of the drill string rests against the wall of the

borehole, which is the case in directional wells, imbedding itself in the filter

cake. The area of the drill pipe in contact with filter cake is then sealed from the

full hydrostatic pressure of the mud column.

The pressure difference between the mud column pressure and the formation

pressure acts on the area of the drill pipe in contact with the filter cake to hold

the drill pipe against the wall of the borehole.

Overpull due to differential pressure sticking can be calculated from the product of

differential pressure, contact area, and a friction factor as follows:

Overpull = (Mud Pressure - Formation Pressure) xContact Area x Friction Factor

where

Overpull (lbs.)

Mud Pressure (psi)

Formation Pressure (psi)

Contact Area (sq in)

Friction Factor (no unit)

Example: If there is a 6 ppg differential pressure across a sand at 7000 ft. T.V.D.

(Mud Pressure - Formation Pressure) = 0.052 x 7000 x 6 = 2184 psi.

Say we have a contact of 3 inches of drill collar circumference across a sand which is 10

thick. That gives a contact area of 360 square inches. From experience, the friction

factors vary from 0.15 to 0.50. We will use 0.15 for this example.

Overpull = 2184 psi - 360 in2

x 0.15

= 117,936.00 lbs.

= 118000 lbs.

An extra overpull of 118 lbs. on top of the normal friction in the wellbore can easily

mean the difference between being free and being stuck. This example also used a

relatively thin sand of 10 feet.

We should actually use the projection of the contact area onto the horizontal plane to be

precise. This is more difficult to visualize and is not used here for simplicity.

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Contact

Area

Mud

Cake

Borehole

Wall

Formation Pressure

Mud Pressure

Figure 13-1 Differential sticking

Filter Cake Thickness The thicker the filter cake, the larger the contact area

with the drill collars and the higher the resulting differential sticking force. The

following illustrates the formation of a filter cake.

Many factors affect the rate of growth and the final thickness of the filter cake.

1. A higher differential pressure will increase the rate of growth of the filter cake. The

final thickness of the cake will be larger in order to seal off the higher pressure.

L

W

P

Figure 13-2 Development of filter cake2. As the amount of drill solids in the mud increases, the filter cake becomes more

porous and permeable. This results in a faster rate of growth of the filter cake and a

larger final thickness. The ideal situation would be a thin, hard filter cake made up of

mud solids only.

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Mud Solids

Drill Solids

Permeable Formation

With a high amount of drill solids, the

filter cake tends to be more porous

and permeable and the final thickness

of the cake tends to be larger.

Permeable Formation

With low amounts of drill solids, the

filter cake tends to be thin and tough

which reduces the chances of

differential sticking.

Pore Pressure

Mud Pressure

High Drill Solids

Pore Pressure

Mud Pressure

Low Drill Solids

Figure 13-3 Effect of drill solids on filter cake3. The lower the water loss or filtrate of the mud, the thinner and harder the filter cake.

In the case of drilling into a sand after undergoing a pressure regression, the

differential pressure is so high that sufficient mud cake can be formed to stick the

BHA while drilling. The best defenses in these cases are proper pore pressure

detection, lowering the mud weight if possible or setting casing.

If the pipe stays motionless (for example, taking surveys in a directional well)

for a period of time adjacent to the sand, the situation gets worse. The filter cake

tends to bridge around the pipe, thus increasing the contact area. The filter cake

in contact with the pipe is no longer in direct contact with the mud and the

friction factor increases by virtue of more water being filtered out of the filter

cake. The end result is that a much greater overpull is required to free thedrillstring.

Contact

Area

Mud

Cake

Bridging

Formation Pressure

Mud Pressure

Figure 13-4 Filter cake bridging

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Filter cake erosion occurs while drilling due to the drill pipe rubbing against the

borehole wall. This only affects a small portion of the circumference of the

wellbore. Wiper trips pull the stabilizers and bit through the filter cake and will

scrape off a significant amount. The best disruption of filter cake is reaming,

where most of the cake will be removed.

Drill Pipe Erosion

While drilling, the drill pipe

is pressed against one

side of the hole. The

rotation of the pipe wears

away a section of filter

cake.

Wiper Trip

A wiper trip will pass the

stabilizers and the bit

across the formatioin

scraping away a large

portion of the filter cake

Reaming

Reaming does the best

job of scraping awaw the

filter cake but is very

time consuming.

Drill Pipe Erosion Wiper Trip Reaming

Figure 13-5 Erosion of filter cake

13.1.1.1 Warning Signs

Permeable formations in open hole, if known.

Thick filter cake on mud tests.

High differential pressure (1500 psi) across the permeable formations, if known.

High torque/overpull after pipe is held motionless.

Higher overpull on connections.

Well developed area with depleted reservoirs. (Talk to Company Man).

13.1.1.2 Stuck Pipe Identification

The pipe was stationary just before sticking usually at a connection while

drilling or tripping Full circulation is possible and pump pressure is unaffected.

BHA is adjacent to thick, permeable formation.

Pressure overbalance at BHA.

Stuck forces get larger with time.

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13.1.1.3 Preventive Actions

1. Pre-well Planning:

Identify any permeable formations which may lead to differential sticking.

Estimate the pressure of permeable formation, using nearby welldata and any

available RFT, DST or producing well data.

If there is a chance of high differential pressure, consider a change in casing

design.

Plan the use of lubricants ahead of time. Spotting fluid must be on location when

differential sticking occurs, otherwise it is useless. Studies show that spotting

fluid must be in place within 4 hours otherwise the chances of the pipe becoming

free are greatly reduced.

Plan on having high quality mud cleaning equipment on the rig to control mud

solids.

Minimize OD of drill collars used to minimize the contact area with the mud

cake. However, annular velocities and borehole cleaning need to be taken into

account when reducing the ODs of drill collars.

13.1.1.4 Rig Site Preparation

Keep the mud weight at the lowest safe level. This will keep differential pressure

across permeable formations at a minimum.

Keep track of the differential pressure across permeable formations as accurately

as possible. This requires maintaining a record or plot of the pressure profile for

the entire open hole section.

Maintain a tough, thin filter cake and keep drilled solids content to a minimum.

Use spiral drill collars and minimize unstabilized sections of the BHA.

If hole drag is not a problem, consider using under-gauge stabilizers on drill

collars to keep them away from the borehole.

Keep the pipe moving at all times. Reciprocating is the preferred motion as it

allows you to monitor overpulls. When possible, begin pipe motion in a

downward direction.

Minimize length of BHA. Use heavy weight drill pipe instead of a long section

of unstabilized drill collars.

Avoid surveying methods which result in pipe remaining static for long periods

(use MWD).

Frequent wiper trips through the permeable zones will scrape the filter cake andmay prevent it from becoming too thick.

13.1.2 Borehole Deterioration

One of the keys for a successful drilling operation, in vertical and directional drilling, is

to control mechanically and chemically the formations being drilled, mainly the shales,

in order to avoid sticking problems. These problems can be associated with any one of

the following cases

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Chemically active formations

Overpressured formations

High dip sloughing

Unconsolidated formations

Mobile formations

Mechanical Stability

The behavior of vertical and directional wells in the first 5 cases above is similar; they

are controlled with the implementation of the correct mud system and operational

procedures.

The formation mechanical stability is a concern when drilling directional wells in general

and high inclination or horizontal wells in particular. When a borehole is drilled, the

process may be thought of as one of replacing the rock which was originally in the hole

with drilling mud. This causes a disturbance to the in-situ stress state local to the hole

because a column of rock which supported three, probably different, principal stresses

(three axes, i.e. two horizontal and one vertical) is replaced by fluid in which the threeprincipal stresses are equal and, typically, lower than any of the stresses in the original

rock column. Unbalanced conditions will generate borehole problems; lost circulation or

hole instability problems (e.g. sloughing or caving). The directional drilling plan,

deviation and azimuth, is a very important factor in the borehole stability.

Over the last years the industry has studied the borehole stability process to define, at the

planning stage, the borehole stability problems that would be faced during the actual

drilling operation. The intention is to identify the in-situ stress state where the well is to

be drilled, to calculate the stresses that will occur at the borehole wall when the well is

drilled and to substitute the borehole wall stresses into shear and tensile failure criteria to

see whether failure occurs. It was found that for a particular formation the upper and

lower formation stability limits (fracture initiation pressure and sloughing/caving

pressure) are greatly affected by the hole inclination and azimuth.

10

11

1213

14

15

16

17

18

19

10 20 30 40 50 60 70 80 90

20

Safe

Working

Area

Fracture - Loss of Circulation

Sloughing - Caving

0

Hole Deviation (deg)

M

udWeight(ppg)

Figure 13-6 Effect of hole deviation & mud weight on borehole stability

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This figure shows the formation behavior, for a set of given conditions, changes with the

hole inclination. It is possible to see that safe drilling conditions are achievable in

inclinations up to 60. Beyond that point, unstability situations would be unevitable.

The same type of analysis can be done for a well to be drilled; knowing the lithology,

formation characteristics and borehole trajectory, a set of plots can be generated:

This type of representation consists of three tracks: the first track gives the mud weightwhich causes tensile failure of the borehole, that is the fracture initiation pressure (FIP);

the second track gives the maximum and minimum mud weights which can be used in

the hole without causing shear failure of the walls; the third track combines the FIP and

the shear failure limits on mud weight to give the maximum and minimum mud weights

which can be used to drill the well. It is possible to see that a vertical well can be drilled

without any borehole stability problems within a wide range of mud weight values;

however, at 50 inclination the operation becomes risky, because of a narrower safe mud

weight range and a totally unstable ledge at 2672m.


1. Formation stability problems in previous wells.

2. New directional well with higher inclination than normal.


1. Use of electric logs for formation stability problem identification.

2. Planning phase.


1. Plan borehole trajectory, inclination and azimuth, within a safe range.

2. Follow a pre-planned mud program.

3. If totally unstable formations are identified, have a contingency plan (short trips,mud lubricity, etc.)

13.1.3 Dog Legs and Key Seats

In order to drill a directional well it is necessary to make controlled dog legs to change

borehole trajectory to reach a desired target. Dog legs are necessary but, simultaneously,

they have been recognized as a major contributing factor for drilling, logging,

completion and production problems, for example.

High friction factors while drilling and tripping (torque and drag).

Key seats.

Failure of drill string components due to excessive reverse bending.

Casing wear.

Extra time to run wire line logs

Problems to run casing and ECP.

Bad cement bond on dog leg high side.

Difficult to set mechanical production packers.

Reduced life time of tubing and sucker rods.

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When a deflecting tool is run in the hole, the directional driller must have permanent

control of the dog legs being generated, in order to take immediate remedial actions to

correct unexpected high dog leg values before continuing to drill. Once a high dog leg

has been created, efforts must be made to reduce the dog leg before drilling ahead.

In this section, the drilling related problems are analyzed.

13.1.3.1 High Friction Factors While Drilling and Tripping

Friction factors are used to evaluate the planned maximum drilling and tripping stresses

while rotating or sliding, to be able to select the proper components to drill the well. Any

deviations from the plan, by making higher dog legs, could result in stopping the drilling

operation without reaching the desired T.D.; this is particularly important in extended

reach and horizontal wells.

The value of the dog leg is defined by the combination of several factors:

Deflecting tool configuration (bent sub/housing angle, distance between

stabilizers).

BHA design.

Drilling parameters.

Formation characteristics (dip angle, formation strength, compactation,

stratigraphy).

Borehole trajectory (inclination and azimuth)

Not all the factors are under our control. Formation characteristics can be estimated, but

they are an unknown until we drill them. For this reason, sometimes higher than expected

dog legs are obtained from a planned BHA, generating more drag and torque.


Unexpected changes of borehole trajectory (inclination and/or azimuth).


Make a comprehensive plan, including torque and drag simulation.

Use previous directional wells data in the same area to identify possible dog leg

problems.

MWD surveys help to detect immediate borehole trajectory changes, so

immediate remedial action should be taken.

13.1.4 Key Seats

Dog legs, even severe ones, do not cause immediate problems as the drill collars are

under compression and accommodate themselves to the new trajectory A key seat is

caused by the drill string in tension, normally drill pipe rubbing against the formation in

the dogleg. If the lateral force at the contact point between the drill string in tension and

the formation is larger than the formation strength, the body and tool joints of drillpipe

start wearing a groove into the formation about the same diameter as the tool joints. The

wear is confined to a narrow groove because the high tension in the drill string prevents

sideways movement. During a trip out of the hole, the BHA may be pulled into one of

these grooves, which maybe too small for it to pass through (see diagram below).

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Key seats are associated with doglegs, as the drill string will be forced into contact with

the formation. The more severe the dogleg and the higher it is up the hole, the greater the

side load will be and so the faster a key seat will develop. Other than doglegs, ledges are

features which provide points of continuous contact. Further variations include key seats

at the casing shoe, where the groove is made in metal instead of rock. Development of

key seats is dependent upon the number of rotating hours and the formation strength.

After creating a

dogleg, the drillstring

is forced against the

borehole wall. Pipe

rotation causes a

groove to be worn

into the formation.

Depending on the

strength of the formation,

the groove will eventually

wear deep into the

formation as shown in

section A-A.

When tripping out of

the hole, the drill collar

will become wedged in

the groove since they

have a larger O.D. than

the drill pipe.

A A

Section A-A

Figure 13-7 Development of key seats


Large doglegs at shallow true vertical depth compared to T.D.

Sticking will occur while tripping out.

Overpull likely to be erratic as tool joints pass through key seat.


First large OD section of BHA reached dogleg.

Circulation unaffected.

Rotation may be possible.


Planning:

Avoid severe doglegs. Directional driller should be given maximum dogleg

tolerances vs TVD guideline for planning the well.

Incorporate key seat reamer (string reamer) into the BHA design if high

torque and drag is not a problem.

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Figure 13-8 Key seat wiper and string reamer.13.1.4.4 Rig Site Preparation

Minimize dogleg severity. Follow maximum dogleg severity guidelines.

Ream any severe doglegs, before key seats have an opportunity to develop.

If a key seat is suspected or expected to develop, consider using a key seat

reamer in the drill pipe to wipe the build section or dogleg.

Minimize the number of correction runs. It is better to make one large correction

run close to target than numerous changes with a steerable assembly at shallow

TVDs.

As soon as problem is recognized, attempt to correct by hole opening run. A high-lubricating pill set at stuck point level will be helpful to free the stuck

drill string.

Jar down when attempting to get free.

13.1.5 Drill String Failures Due to Excessive Reverse Bending

The stress to which the drill string components are subjected when rotating through a

dogleg change from tension to compression every 1/2 turn, accelerates fatigue wear. As a

result the life of the drill pipe and drill collar connections will be reduced or rig time is

likely to be lost due to wash outs, twist offs, etc.


Have superior grade quality tubulars.

Apply recommended make up torque to connections using proper equipment.

Implement a systematic pipe inspection system.

Use an adequate safety factor. Make a proper torque and drag plan.

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13.1.6 Equipment Compatibility

Modern directional drilling practices require the use of new technology; bits, downhole

motors, MWD systems, solids control system, pumps, etc.; it is common to have multiple

suppliers for these elements. The operational requirements and limits are different for

each one. The drilling performance can be seriously affected if the right parameters are

not used. Special care must be taken in the following areas: Maximum and minimum GPMs

Pressure losses through the drillstring.

RPM.

Weight on bit.

Maximum operating pressure.

Operating changes, if formation changes occur.

Downhole static and circulating temperatures.

Length of the bit run. Initial and final surface pressures.


Know the technical and operational specifications of every tool run in the hole.

Know the technical and operational specifications of the rig and surface system.

Make hydraulic calculations before running in the hole.

Verify the compatibility of the BHA elements.

Define the expected formations and lithology to be drilled during the bit run.

13.1.7 Borehole Stability

Packing off:

Poor hydraulics and mud conditioning will lead to the hole packing off. Solids will build

up in the mud and plug up the annulus while in turbulent flow. Remedy: Shut down the

pumps, thereby reducing ECD and annular velocity. Attempt to free pipe by jarring down

and, if possible, rotating. If circulation can be established, bring pumps up to speed very

slowly and circulate the hole clean.

Mud Motor Sliding:

When a mud motor is in sliding mode, it becomes very difficult to maintain a constant

WOB. In the worst case, all the surface weight can be slacked off with no change in

WOB. This is due to high sliding friction (Drag).

Remedy:

To improve the sliding condition, add walnut hulls to the mud system. This helps to keep

the PDM and BHA off the borehole wall and hence allow sliding to continue. Sweeping

the hole with a low-vie pill and LCM should help to reduce friction. (The LCM must be

fine-to-medium, well-mixed). As a last resort, POOH and run a hole opener through the

problem section.

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