lecture 13 (Drilling Problems)

Drilling Problems

13 Drilling Problems

About this chapter

The development of new technologies in the past 10 years, 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.

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 this

manual, it is the DD’s responsibility to ascertain the client’s 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 80’s, 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.

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.

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.

 ·  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 three
principal 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.

 

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 60º. 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 weight

which 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.

13.1.2.1 Warning Signs

1. Formation stability problems in previous wells.

2. New directional well with higher inclination than normal.

13.1.2.2 Stuck Pipe Identification

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

2. Planning phase.

13.1.2.3 Preventive Actions

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.

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.

13.1.3.2 Warning Signs

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

13.1.3.3 Preventive Actions

·  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).

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.

13.1.4.1 Warning Signs

·  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.

13.1.4.2 Stuck Pipe Identification

·  First large OD section of BHA reached dogleg.

·  Circulation unaffected.

·  Rotation may be possible.

13.1.4.3 Preventive Actions

·  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.

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.

13.1.5.1 Preventive Actions

·  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.

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 GPM’s

·  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.

13.1.6.1 Preventive Actions

·  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.