lecture 6 (Drilling Jars)

Drilling Jars

About this chapter

Until recently, the Earthquaker Drilling Jar and the Shock Guard were the only two DD

tools which were provided directly by Anadrill for the drilling of directional wells.

The Earthquaker is still the most reliable and effective mechanical drilling jar on the

market. Clients have confidence in the Earthquaker because of its track record.

This chapter is designed to explain the theory and operation of the EQ Jars. Their

position in the BHA and the constraints thereon are covered here and in Chapter 11.

It is recommended that, in addition to this DD training manual, the Anadrill DD carry the

EQ Jar manual with him on every job. The manual has additional information (e.g.

rig-floor tripping load adjustment, EQ Jar specifications and fishing diagrams) which are

beyond the scope of this book.

Objectives of this Chapter

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

exercises:

1. Describe the objective of jarring.

2. Describe the different types of jars available.

3. Describe how the tripping mechanism of the EQ Jar operates.

4. List the advantages and disadvantages of the EQ Jar vis-a-vis hydraulic jars.

5. Describe the major constraints on EQ Jar position in the BHA.

6. Show what is meant by Pump Extension Force.

7. Calculate the weight indicator reading when the driller jars DOWN. Assume the

pumps are on and there is wall drag.

8. Show how the driller cocks the EQ Jars

·  after jarring UP

·  after jarring DOWN

9. Calculate the maximum allowable UP setting for the EQ Jar.

6.1 Using Drilling Jars

6.1.1 Drilling Jars

Drilling jars are run as part of most directional BHAs. On vertical wells, drilling jars

may or may not be run, depending on the client. Drilling jars are designed to deliver an

impact in either an upward or a downward direction. Some jars work in one direction

only.

Inside, a jar is basically a sliding mandrel that allows a brief and sudden axial

acceleration of the drillstring above the jar. Travel of this mandrel (the hammer) is

limited by a stop (anvil) on the outer sleeve (Figure 6-1).

6.1.1.1 Jarring Objective

To transfer the potential energy stored in the stretched drill pipe to kinetic energy in the

BHA above the jars. At the end of the jar stroke, a stress wave is sent to the stuck pipe.

The magnitude of the stress wave is related to the velocity of the accelerated BHA. The

duration of the wave is related to the length of the BHA.

Kinetic Energy =

1

2

MV2

M = Mass (weight) of BHA above the jar

V = Velocity (speed) at which the mass is moving when the jar fires (hammer strikes

anvil) in feet/second.

There are three types of drilling jars:

·  Mechanical

·  Hydraulic

·  Hydromechanical.

6.1.1.2 Mechanical Jars

Mechanical jars operate using a series of springs, lock and release mechanisms.

Hydraulic jars operate using the controlled passage of hydraulic fluid. Hydromechanical

jars are a hybrid of both designs, usually hydraulic up and mechanical down.

A mechanical jar trips up at a preselected tensile force, and trips down at a preselected

compressional force. The jar trips only at the set threshold. This is normally beyond the

forces reached while drilling. The position of the mechanical jar while drilling is either

cocked (neutral) or extended. Drilling is never conducted with the jars tripped down as

unnecessary jarring might damage the bit and BHA components.

The release mechanism of a mechanical jar is set either downhole or at surface,

depending on jar design. There are two main designs. One uses the principle of the

torsion spring. These mechanical jars are delivered to the rig with specific up and down

tripping load settings. Their release force can be varied downhole by 10 - 15% by

applying torque to the drillstring. Left- hand torque decreases spring tension; right-hand

torque increases it. The Dailey L.I. Jar uses this design. Another design uses an

expanding sleeve with slots, lugs and ancillary springs. The overpull necessary to trip the

jar can be reduced downhole by increasing mud flow rate. The Anadrill Earthquaker

(EQ) Drilling Jar uses this latter design. It will be covered in some detail later in this

chapter.

6.1.1.3 Hydraulic Jars

A hydraulic jar consists of two reservoirs of hydraulic fluid separated by a valve. When

tension or compression is applied to the tool in the cocked position, fluid from one

chamber is compressed and passes through the valve at high flow resistance into the

second chamber. This allows the tool to extend or contract. The distance traveled is

called the metered stroke. When the stroke reaches a certain point, the compressed fluid

is allowed to suddenly bypass the valve. The valve trips as the fluid rushes into the

second chamber, instantly equalizing pressures between the two chambers. The greater

the force on the jar, the greater the compression of the fluid and the sooner and more

forceful the release. This is the principle of the Anadrill Hydraquaker Drilling Jar

(Figure 6-2).

Hydraulic jars do not trip at a preselected threshold. When, and how forcefully, the jar

trips is determined by the magnitude of the applied tension or compression. To trip up,

the force of the blow is proportional to the overpull. The greater the overpull on the

drillstring, the sooner the jars trip and the harder the blow. Thus, the hydraulic jar has the

advantage of having a continuously-variable jarring force, within its design limits.

Another advantage of hydraulic jars is that, for sizes 6 1/2" OD, they have a larger ID

than comparable mechanical jars.

Once a hydraulic jar is cocked, it will fire if given enough time to complete the metered

stroke. This gives hydraulic jars an advantage in high-angle and horizontal wells. Here,

excess drag may prevent the driller from applying sufficient tension or compression to

trip a mechanical jar. A cocked hydraulic jar will eventually fire, even with minimal

tension or compression. However, this can be a disadvantage also, as accidental jarring

(particularly in vertical wells) with the pipe in slips is dangerous and could lead to a

fishing job.

Repeated jarring with a hydraulic jar can lead to overheating of the hydraulic fluid. This

reduces its viscosity, shortening the metering time and tripping the jar before the desired

tension can be applied. Consequently, jarring force decreases over time. Although some

changes have occurred recently, an adequate design for hydraulic jars has yet to be

proven i.e. visco jets.

 

One major advantage of mechanical jars is that they will not fire until the threshold

setting is reached. They are often perceived as being more rugged and durable than

hydraulic jars.

6.1.1.4 How does the Earthquaker (EQ) Drilling Jar Work ?

The major external components of the EQ Jar are shown in Figure 6-3. Note that some

EQ Jars (older design) have a Jack Nut. The new design dispenses with the Jack Nut.

The function of the Jack Nut was to extend the EQ Jar prior to running in the hole to

drill. This is no longer deemed necessary (See below).

The EQ Jar has a relatively simple tripping mechanism that can be adjusted on surface, if

required. In the EQ Jar, the relationship between the Trip Mandrel, Trip Sleeve, Friction

Sleeve, Adjusting Sleeves and Spring Tubes (Figure 6-4) is what determines whether the

jar is cocked or tripped. The Trip Sleeve acts as a radial spring along its length. The

Spring Tubes are sets of three concentric tubular springs having a very high spring rate

(only 0.1" reduction in length for a compressive load of 100,000 lbs.).

Figure 6-4 is an expanded view of the EQ Jar tripping mechanism in four different

positions, one of which (position 2) is a "snapshot". In the cocked position, the Trip

Sleeve is in its normal state. It is closed around the Trip Mandrel, with the teeth and

grooves on the ID of the Trip Sleeve meshed with the teeth and grooves on the OD of the

Trip Mandrel. The teeth on the OD of the Trip Sleeve contact the teeth on the Friction

Sleeve crest-to-crest. The Friction Sleeve is held securely inside the Middle Housing and

acts as an integral part of the housing.

The housings are free to slide up and down a fraction of an inch over the Trip Mandrel

until the Spring Tubes contact the end of the Trip Sleeve. Adjusting Sleeves, threaded

into the housings at top and bottom, control the amount of free movement. Rotation of

the Adjusting Sleeves controls the amount of free movement and changes the point

where resistance is encountered. It is the Adjusting Sleeves which are rotated to a

number of different positions (corresponding to specific tripping loads) when the EQ Jar

is calibrated in the workshop. On the rig, if the "UP" or "DOWN" trip settings have to be

adjusted, the lower or upper adjusting sleeve, respectively, is rotated to the desired

position, corresponding to a specific tripping load on the EQ Jar calibration sheet (Refer

to EQ Jar Manual).

When contact is made between the Trip Sleeve and the Spring Tubes, additional pushing

or pulling of the EQ Jar causes compression to begin in either the Upper or Lower Spring

Tube, respectively. As tension on the tool increases, pressure grows between the Trip

Sleeve and Trip Mandrel teeth. The high spring rate of the Spring Tubes at the end of the

Trip Sleeve and the contact angle of the Trip Mandrel teeth on the Trip Sleeve teeth,

forces the Trip Sleeve to expand. This expansion is restricted by the Friction Sleeve teeth

which are positioned to confine the Trip Sleeve. The Spring Tubes compress until the

Housing and Friction Sleeve have moved enough that the Trip Sleeve is no longer

constrained by the Friction Sleeve teeth. This point is determined by the EQ Jar setting.

At this point, the Trip Sleeve instantaneously expands off the Trip Mandrel and engages

with the teeth and grooves on the ID of the Friction Sleeve. The Housings, now free to

move, accelerate up or down until the Hammer strikes the Anvil. This completes the

jarring cycle. The Trip sleeve expansion is maintained through the free stroke by

Expansion Pads at either end of the Trip Sleeve.

Recocking of the jar occurs as the Trip Sleeve, still engaged with the Friction Sleeve, is

repositioned over the Trip Mandrel. When the teeth of the Trip Sleeve realign with the

teeth on the OD of the Trip Mandrel, the Trip Sleeve returns to its normal position by

closing around the Trip Mandrel and disengaging form the Friction Sleeve. With the

tension no longer applied, the Spring Tubes extend to their full length, completing the

recocking. The cycle is now ready to repeat, in either direction, as often as possible.

To summarize, following are the three “major” positions of the EQ Jar (Figure 6-5):

1. Jar Tripped Down The mandrel has been released from the Trip Sleeve and

expanded into the Friction Sleeve in the “jarred down” position.

2. Jar Cocked The mandrel is locked in position inside the Trip Sleeve, with preset

loads restrining the Trip Sleeve crest-to-crest with the teeth of the Friction Sleeve.

The Spring Tubes are relaxed.

3. Jar Tripped Up The mandrel has been released from the Trip Sleeve and expanded

into the Friction Sleeve in the jarred up position. The jar is in tension for running in

the hole and drilling.

6.1.1.5 Features of the EQ Jar

1. With the EQ Jar in the drillstring, the driller can start jarring up or down

immediately if the pipe becomes stuck.

2. Both up and down tripping loads can be independently adjusted to a maximum of

180,000 lbs. (for some sizes) either in the workshop or at the rig-site (Refer to EQ

Jar manual). Torque has no effect on these preset hitting loads.

3. The EQ Jar spline system (for rotation) means that there is no torsional slack in the

mandrel. This is useful in DD work, especially when orienting.

4. The working parts are enclosed in oil to minimize wear or malfunction due to mud

solids etc.

5. A compensating piston minimizes pressure differentials on all seals. Preloaded

V-packing on moving seal areas eliminates both high and low pressure leaks.

6. The jar will trip at the same preset load, regardless of time in the hole or downhole

temperature.

7. Internal compensation allows for high extension force and compression placements.

It also provides a means for downhole load adjustment.

BASIC LOG TYPES

BASIC LOG TYPES

Below is a list of the main types of logs that may be run, and why they

are run.

1.2.1 Logging While Drilling (LWD)

Traditionally, petrophysicists were concerned only with wireline

logging, that is, the data acquired by running tools on a cable from a winch

after the hole had been drilled. However, advances in drilling/logging

technology have allowed the acquisition of log data via tools placed in

the actual drilling assembly. These tools may transmit data to the surface

on a real-time basis or store the data in a downhole memory from which

it may be downloaded when the assembly is brought back to the surface.

LWD tools present a complication for drilling, as well as additional

expense. However, their use may be justified when:

• Real-time information is required for operational reasons, such as

steering a well (e.g., a horizontal trajectory) in a particular formation

or picking of formation tops, coring points, and/or casing setting depths

• Acquiring data prior to the hole washing out or invasion occurring

• Safeguarding information if there is a risk of losing the hole

• The trajectory is such as to make wireline acquisition difficult (e.g., in

horizontal wells)

LWD data may be stored downhole in the tools memory and retrieved

when the tool is brought to the surface and/or transmitted as pulses in the

mud column in real time while drilling. In a typical operation, both modes

will be used, with the memory data superseding the pulsed data once the

tool is retrieved. However, factors that might limit the ability to fully use

both sets of data are:

• Drilling mode: Data may be pulsed only if the drillstring is having mud

pumped through it.

• Battery life: Depending on the tools in the string, tools may work in

memory mode only between 40 and 90 hours.

• Memory size: Most LWD tools have a memory size limited to a few

megabytes. Once the memory is full, the data will start to be overwritten.

Depending on how many parameters are being recorded, the

memory may become full within 20–120 hours.

• Tool failure: It is not uncommon for a fault to develop in the tool

such that the pulse data and/or memory data are not transmissible/

recordable.

Some of the data recorded may be usable only if the toolstring is rotating

while drilling, which may not always be the case if a steerable mud

motor is being used. In these situations, the petrophysicist may need to

request drilling to reacquire data over particular intervals while in

reaming/rotating mode. This may also be required if the rate of penetration

(ROP) has been so high as to affect the accuracy of statistically based

tools (e.g., density/neutron) or the sampling interval for tools working on

a fixed time sampling increment.

Another important consideration with LWD tools is how close to the

bit they may be placed in the drilling string. While the petrophysicist will

obviously want the tools as close to the bit as possible, there may be

limitations placed by drilling, whose ability to steer the well and achieve

a high ROP is influenced by the placement of the LWD toolstring. LWD

data that may typically be acquired include the following:

• GR: natural gamma ray emission from the formation

• Density: formation density as measured by gamma ray Compton scattering

via a radioactive source and gamma ray detectors. This may also

include a photoelectric effect (Pe) measurement.

• Neutron porosity: formation porosity derived from the hydrogen index

(HI) as measured by the gamma rays emitted when injected thermal

or epithermal neutrons from a source in the string are captured in the

formation

• Sonic: the transit time of compressional sound waves in the formation

• Resistivity: the formation resistivity for multiple depths of investigation

as measured by an induction-type wave resistivity tool

Some contractors offer LWD-GR, -density, and -neutron as separate

up/down or left/right curves, separating the contributions from different

quadrants in the borehole. These data may be extremely useful in steering

horizontal wells, where it is important to determine the proximity of

neighboring formation boundaries before they are actually penetrated.

Resistivity data may also be processed to produce a borehole resistivity

image, useful for establishing the stratigraphic or sedimentary dip and/or

presence of fractures/vugs.

Other types of tool that are currently in development for LWD mode

include nuclear magnetic resonance (NMR), formation pressure, and shear

sonic.

1.2.2 Wireline Openhole Logging

Once a section of hole has been completed, the bit is pulled out of the

hole and there is an opportunity to acquire further openhole logs either

via wireline or on the drillstring before the hole is either cased or abandoned.

Wireline versions of the LWD tools described above are available,

and the following additional tools may be run:

• Gamma ray: This tool measures the strength of the natural radioactivity

present in the formation. It is particularly useful in distinguishing

sands from shales in siliciclastic environments.

• Natural gamma ray spectroscopy: This tool works on the same principal

as the gamma ray, although it separates the gamma ray counts into

Basics 5

three energy windows to determine the relative contributions arising

from (1) uranium, (2) potassium, and (3) thorium in the formation. As

described later in the book, these data may be used to determine the

relative proportions of certain minerals in the formation.

• Spontaneous potential (SP): This tool measures the potential difference

naturally occurring when mud filtrate of a certain salinity invades the

formation containing water of a different salinity. It may be used to

estimate the extent of invasion and in some cases the formation water

salinity.

• Caliper: This tool measures the geometry of the hole using either two

or four arms. It returns the diameter seen by the tool over either the

major or both the major and minor axes.

• Density: The wireline version of this tool will typically have a much

stronger source than its LWD counterpart and also include a Pe curve,

useful in complex lithology evaluation.

• Neutron porosity: The “standard” neutron most commonly run is a

thermal neutron device. However, newer-generation devices often use

epithermal neutrons (having the advantage of less salinity dependence)

and rely on minitron-type neutron generators rather than chemical sources.

• Full-waveform sonic: In addition to the basic compressional velocity

(Vp) of the formation, advanced tools may measure the shear velocity,

Stonely velocity, and various other sound modes in the borehole,

borehole/formation interface, and formation.

• Resistivity: These tools fall into two main categories: laterolog and

induction type. Laterolog tools use low-frequency currents (hence

requiring water-based mud [WBM]) to measure the potential caused by

a current source over an array of detectors. Induction-type tools use

primary coils to induce eddy currents in the formation and then a secondary

array of coils to measure the magnetic fields caused by these

currents. Since they operate at high frequencies, they can be used in

oil-based mud (OBM) systems. Tools are designed to see a range of

depths of investigation into the formation. The shallower readings have

a better vertical resolution than the deep readings.

• Microresistivity: These tools are designed to measure the formation

resistivity in the invaded zone close to the borehole wall. They operate

using low-frequency current, so are not suitable for OBM. They are

used to estimate the invaded-zone saturation and to pick up bedding

features too small to be resolved by the deeper reading tools.

• Imaging tools: These work either on an acoustic or a resistivity principle

and are designed to provide an image of the borehole wall that may

6 Well Logging and Formation Evaluation

be used for establishing the stratigraphic or sedimentary dip and/or

presence of fractures/vugs.

• Formation pressure/sampling: Unlike the above tools, which all “log”

an interval of the formation, formation-testing tools are designed to

measure the formation pressure and/or acquire formation samples at a

discrete point in the formation. When in probe mode, such tools press

a probe through the mudcake and into the wall of the formation. By

opening chambers in the tool and analyzing the fluids and pressures

while the chambers are filled, it is possible to determine the true pressure

of the formation (as distinct from the mud pressure). If only pressures

are required (pretest mode), the chambers are small and the

samples are not retained. For formation sampling, larger chambers are

used (typically 23/4 or 6 gallons), and the chambers are sealed for analysis

at the surface. For some tools, a packer arrangement is used to enable

testing of a discrete interval of the formation (as opposed to a probe

measurement), and various additional modules are available to make

measurements of the fluid being sampled downhole.

• Sidewall sampling: This is an explosive-type device that shoots a sampling

bullet into the borehole wall, which may be retrieved by a cable

linking the gun with the bullet. Typically this tool, consisting of up to

52 shots per gun, is run to acquire samples for geological analysis.

• Sidewall coring: This is an advanced version of the sidewall sampling

tool. Instead of firing a bullet into the formation, an assembly is used

to drill a sample from the borehole wall, thereby helping to preserve

the rock structure for future geological or petrophysical analyses.

• NMR: These tools measure the T1 and T2 relaxation times of the formation.

Their principles and applicability are described in Chapter 5.

• Vertical seismic profiling (VSP): This tool fires a seismic source at the

surface and measures the sound arrivals in the borehole at certain depths

using either a hydrophone or anchored three-axis geophone. The data

may be used to build a localized high-resolution seismic picture around

the borehole. If only the first arrivals are measured, the survey is typically

called a well shoot test (WST) or checkshot survey. VSPs or

WSTs may also be performed in cased hole.

1.2.3 Wireline Cased Hole Logging

When a hole has been cased and a completion string run to produce the

well, certain additional types of logging tools may be used for monitoring

purposes. These include:

• Thermal decay tool (TDT): This neutron tool works on the same principle

as the neutron porosity tool, that is, measuring gamma ray counts

when thermal neutrons are captured by the formation. However, instead

of measuring the HI, they are specifically designed to measure the

neutron capture cross-section, which principally depends on the amount

of chlorine present as formation brine. Therefore, if the formation water

salinity is accurately known, together with the porosity, Sw may be

determined. The tool is particularly useful when run in time-lapse mode

to monitor changes in saturation, since many unknowns arising from

the borehole and formation properties may be eliminated.

• Gamma ray spectroscopy tool (GST): This tool works on the same principal

as the density tool, except that by measuring the contributions

arising in various energy windows of the gamma rays arriving at the

detectors, the relative proportions of various elements may be determined.

In particular, by measuring the relative amounts of carbon and

oxygen a (salinity independent), measurement of Sw may be made.

• Production logging: This tool, which operates using a spinner, does not

measure any properties of the formation but is capable of determining

the flow contributions from various intervals in the formation.

• Cement bond log: This tool is run to evaluate the quality of the cement

bond between the casing and the formation. It may also be run in a circumferential

mode, where the quality around the borehole is imaged.

The quality of the cement bond may affect the quality of other production

logging tools, such as TDT or GST.

• Casing collar locator (CCL): This tool is run in order to identify the

positions of casing collars and perforated intervals in a well. It produces

a trace that gives a “pip” where changes occur in the thickness of the

steel.

1.2.4 Pipe-Conveyed Logging

Where the borehole deviation or dogleg severity is such that it is not

possible to run tools using conventional wireline techniques, tools are typically

run on drillpipe. In essence, this is no different from conventional

logging. However, there are a number of important considerations.

Because of the need to provide electrical contact with the toolstring, the

normal procedure is to run the toolstring in the hole to a certain depth

before pumping down a special connector (called a wet-connect) to

connect the cable to the tools. Then a side-entry sub (SES) is installed in

the drillpipe, which allows the cable to pass from the inside of the pipe

to the annulus. The toolstring is then run in farther to the deepest logging

point, and logging commences. The reason the SES is not installed when

the toolstring is at the surface is partly to save time while running in (and

allowing rotation), and also to avoid the wireline extending beyond the

last casing shoe in the annulus. If the openhole section is longer than the

cased hole section, the logging will need to be performed in more than

one stage, with the SES being retrieved and repositioned in the string.

Pipe-conveyed logging is expensive in terms of rig time and is typically

used nowadays only where it is not possible to acquire the data via LWD.

Most contractors now offer a means to convert an operation to pipeconveyed

logging if a toolstring, run into the hole on conventional wireline,

becomes stuck in the hole. This is usually termed “logging while fishing.”