Q922+de2+l09 v1

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D rilling E ngineering 2 Course ( 2 nd Ed.)

description

 

Transcript of Q922+de2+l09 v1

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1. Necessity of Directional well

2. well’s trajectory

3. Major Types of Wellbore Trajectories

4. Trajectory rule of thumbs and terms

5. Trajectory Calculation

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1. the Survey of a Well

2. Calculating the Survey of a Well

3. Deflection Tools and Techniques

4. Hydraulic Method (Jetting)

5. Mechanical Methods

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survey stations

When drilling a well, inclination, azimuth and MD are measured at various so called “survey stations”. This is done with survey tools

to check the actual traverse of the well.

These measurements are then used for (a) estimation of the real trajectory path,

(b) comparison with the planned well trajectory and

(c) planning necessary steps to re-direct the well to reach the desired location.

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Survey tools

Sketch of a Single shot and Multishot tool Sketch of a gyroscopeSpring14 H. AlamiNia Drilling Engineering 2 Course (2nd Ed.) 6

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Survey tools

The tools to measure the inclination and azimuth at the survey stations can be as simple as dropping tools (totco, measures only

inclination, thus only used for vertical wells) like single (one measurement per tool run) or

multishot magnetic instruments and gyroscopes, or

sophisticated measurement while drilling tools that

• are assembled within the drillstring (close to the bit) and nearly continuously measure the desired directional parameters or

logging while drilling tools that • also make measurements of the formations penetrated for online

trajectory re-designing (e.g. following a geological horizon).

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full survey

The direction angles obtained by magnetic tools must be corrected for true north and the gyroscope corrected for drift since the magnetic north does not coincides with the true north.

Next Figure shows a map of these correction angles for various locations.

With these corrected azimuth and inclination values, a so called full survey (containing TVD, horizontal departure, etc.) is calculated.

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Declination map

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Full survey methods

To obtain the full survey from MD, inclination and azimuth, various methods that depend on different models are proposed.

Below is a list of the most popular ones:Acceleration methodAverage angle methodAngle-averaging methodBackward station methodBalanced tangential methodCircular arc methodCompensated acceleration

methodMercury methodMinimum curvature method

(the most accurate)

Quadratic methodRadius of curvature method

(the most accurate)

Secant methodTangential method

(the simplest one but gives inaccurate results)

Terminal angle methodTrapezoidal methodVector averaging method

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Average angle method

α [◦] hole angle

𝜖[radian] azimuth

DMi [ft] measured depth between two survey stations

Li[ft] north/south coordinate between the two stations

Mi [ft] east/west coordinate between the two stations

The total north/south and east/west coordinates and the TVD value are computed with:

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Radius of curvature method

where:

When < 0.25 [radians], F can be set to 1.0

𝛽[radians] curvature or the dogleg

F [1] ratio factor used to smooth the wellbore between the two survey stations

𝛼1 inclination at station 1

𝛼2 inclination at station 2

𝜖1 azimuth at station 1

𝜖1 azimuth at station 2

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Minimum Curvature Method

where:DL [/100 ft] dog leg

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Dogleg Severity

By definition, a dogleg is a sudden change of inclination and/or

direction of a well’s trajectory.

For description purpose, the change is usually expressed in a 100-[ft] interval ([◦/ 100 ft]) and

called “dogleg severity”.

As it has been seen in practice, large dogleg severities can lead to failure of drillpipe, drill collar or tool joints as well as

create so called “keyseats” which result in stuck drillstrings.

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Dogleg Severity Calculations

To obtain the dogleg severity, the survey calculated with one of the methods described above is used along with following equations:

δ [◦/100 ft] dogleg severityβ [◦] total angle of change (turn)αN [◦] new inclinationΔ𝜖 [◦] change in azimuth∆α [◦] change in inclinationLc [ft] length over which change of trajectory occurs

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drillpipe protector

To reduce the wear-effect of large dogleg severities, the add of multiple steel or rubber drillpipe protectors which are

cylindrical pieces,

having an outside diameter equal to the outside diameter of the tool joints, have proven to be efficient.

drillpipe protectorsSpring14 H. AlamiNia Drilling Engineering 2 Course (2nd Ed.) 17

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actual vs. planned trajectory

The methods presented above calculate the trajectory path of the well as it is drilled. The actual trajectory is

constantly compared with the planned one and in case the actual one is

going of course (which it always does to some extend),correction steps to bring

the trajectory on course again have to be taken.

To correct the course of the well in case of minor

deflections, an experienced driller can

vary the individual drilling parameters (WOB, RPM, etc.) to adjust for the of-going trajectory.

In case the trajectory is largely of course, a deflection tool

has to be run and drilling in sliding mode (e.g. positive displacement motor (PDM)) carried out to make the necessary correction.

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The well direction determination

To determine the direction the well is drilled in sliding mode, the bottom hole assembly

containing the deflection tool is rotated from the surface by rotating the whole drill string.

Then, either a so called “Ragland vector diagram” or the following equations are applied to compute the tool face

orientation.

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Calculation of the new inclination and direction angles The computational results have shown to be more

accurate than the graphical one gained from the Ragland vector diagram. The tool face angle is given by:

The new inclination and direction angles are:

for γ is right of high side of the borehole:

and for γ is left of high side of the borehole:𝜖𝑁 [◦] new direction of the trajectory

αN [◦] new inclination of the trajectory

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special deflection tools

Although rotary assemblies can be designed to alter the path of the wellbore, there are certain

circumstances where it is necessary to use special deflection tools, for example kicking-off and

sidetracking.

These special tools include jetting bits, whipstocks, and

downhole motors with a deflection device.

In drilling operations, the bit is forced under weight and rotation to cut a certain diameter hole. As the bit penetrates along

the vertical axis, it also moves laterally.

This movement can range from very small to considerable displacement. This displacement

can be represented in three dimensions.

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The various methods of deviations

Directional drilling is to cause the bit to deviate in a controlled manner.

The various methods used to induce the bit to build, drop and turn can be classed into mechanical and hydraulic methods

besides the natural formation effects.

Mechanical techniques include whipstocks, bottom hole assemblies, and down hole motors

with bending device.

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Different methods to deflect the trajectory of a borehole

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Natural Formation Effects

The formations encountered when drilling oil wells are very rarely homogeneous and isotropic. One is more likely to find a sequence of different layers,

with each layer having its own drillability characteristics.

The bit may have to drill through alternating layers of hard and soft rocks.

Furthermore, these strata may not be lying evenly in horizontal beds

but instead be dipping at some angle.

The geology may be further complicated by faulting and folding of the strata.

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Effect of dipping on well deviation

As the bit drills across a formation boundary, it will tend to be deflected from its original course.

Experience has shown that where the formations are steeply dipping

(greater than about 60◦) the bit tends to drill parallel with the bedding planes.

Where the formation dip is less steep, the bit tends to drill at right angles to the bedding planes.

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Bit walk & drilling related effects

In addition to changes in inclination there may also be changes in direction in which case the bit will tend to walk. Under normal rotary drilling,

the bit will tend to walk to the right,

but with a downhole motor the effect of reactive torque may force it to the left.

Drilling parameters such as: weight on bit, RPM, and hydraulics,

will also affect the amount of deviation.

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Jetting technique

This method of changing the trajectory of a wellbore requires the use of a jetting bit

to wash away the formation.

Water or drilling mud is pumped through a large jet that is oriented in the direction of the desired trajectory change.

Jetting is a technique best suited to soft-medium formation in which

the compressive strength is relatively low and hydraulic power can be used

to wash away a pocket of the formation to initiate deflection.

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Bit design of jetting technique

The amount of inclination produced is also related to the type of bottom hole assembly used with the jetting bits.

There are two commercial bits especially designed for the jetting technique. One is a two-cone bit

with an extended jet replacing the third cone and the second one is a conventional three cone bit

with two small and one large “big eye” jet.

The actual design of the jetting process is a function of hole size, pump capacity, expected formation hardness, and the desired bit cleaning efficiency while drilling.

Compared to trajectory deflection using a whipstock or downhole motors, jetting is the most approximate method.

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Procedure of jetting technique

On any particular run, the bit is mounted on an assembly, which

includes an orienting sub and a full-gauge stabilizer near the bit. Once the bit touches the bottom,

the large nozzle is oriented in the required direction. Maximum circulation rate is used

to begin washing without rotating the drill string. The pipe is worked up and down with continuous jetting,

until a pocket is washed away. At this stage the drill string can be rotated

to ream out the pocket and continue building angle

as more weight is applied to the bit. Surveys are taken frequently

to ensure that the inclination and direction are correct.

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pros and cons of jetting technique

Advantages of this method are: several attempts can be made to initiate deflection

without pulling out of the hole, a full gauge hole can be drilled from the beginning.

Disadvantages of this method are: the technique is limited to soft-medium formations, severe dog-legs can occur

if the jetting is not carefully controlled, on smaller rigs there may not be enough pump capacity

to wash away the formation.

In summary, jetting is a very cost-efficient giving that kicking-off takes place under suitable geological conditions.

In general it requires a good directional monitoring.

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mechanical methods

All mechanical methods rely on the application of an appropriate side force

which causes the bit to deviate. When the imposed side force on the bit is positive,

an angle is build up,

when it is negative, the force drops the angle.

Common mechanical techniques used to deflect the bit are: whipstocks,

downhole motors with bending device,

and bottom hole assembly.

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Whipstocks

The whipstock method to deviate a bit is the oldest technique and,

if properly used, the most reliable one.

In comparison with other alternative methods, it is the most time consuming one.

A whipstock can be as simple as a kick-off sub at the end of

a conductor pipe or casing, or it can be

a more sophisticated retrievable jetting whipstock.

Although there are a number of variations all whipstocks work on the principle of creating a curvature.

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Whipstock application

The successful use of a whipstock is largely a matter of knowing when to run a whipstock in relation to other mechanical or hydraulic devices.

In today’s industry, the whipstock is predominately used for sidetracking out the casing pipe, which is called “casing whipstock”.

also it can be used to side-track out the open hole when hydraulic jetting or running a mud motor

fails to deviate the well. Which is called “open hole whipstock”.

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Deflection with a Whipstock

A whipstock can be described as a steel wedge with a chisel shaped point at the bottom. This chisel shape

prevents the whipstock from turning when drilling begins.

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The whipstock installation

The whipstock, that is run down hole, is attached to the lower end of the drill string

by means of a shear pin.

It is either set on the bottom or anchored and locked in a packer which was previously installed in a casing string.

A modern whipstock has a tapered concave groove, called the tool face,

which helps in orienting the whipstock.

Once it is installed down hole, it guides the bit or the mill against the casing or

the open hole wall to drill in the desired direction.

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1. Dipl.-Ing. Wolfgang F. Prassl. “Drilling Engineering.” Master of Petroleum Engineering. Curtin University of Technology, 2001. Chapter 9

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1. Whipstock Running Procedures

2. Adjustable bent sub above motor

3. Motor housing with one or two bends

4. Offset Stabilizer on Motor

5. While Drilling TechniquesA. Data Transfer

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