Pipe Rotation Effect For Hole Cleaning For Water Based Drilling Fluid in Horizontal & Deviated Wells

This article written by Technology Editor Dennis Denny, contains highlights of paper SPE 114965 "Pipe Rotation Effect For Hole Cleaning For Water Based Drilling Fluid in Horizontal & Deviated Wells", by M.E. Ozbayoglu, Middle East Technical University; A. Saasen, Middle East Technical University; and K. Svanes, StatoilHydro, prepared for the 2008 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Jakarta, 25-27 August. The Paper has not been peer reviewed. 

Directional Drilling

What is Directional Drilling?

Directional drilling is the science of deviating a wellbore along a planned path to a target located at a given lateral distance and direction from vertical. This includes drilling as vertically as possible from a given TVD.

The figure below shows a vertical well and a deviated well.

As a starter one can consider that any well which gets deviated from the vertical axis to achieve the desired target (hydrocarbon reserve in our case) may be termed as deviated well (or Directional well). 

 

Vertical Versus Deviated Wells

What are the applications of Directional Drilling?

1. Side Tracking

Sidetracking is one of the primary uses for directional drilling. Sidetracking is an operation which deflects the borehole by starting a new hole at any point above the bottom of the old hole as in Figure below. 

The primary reason for sidetracking is to bypass a fish which has been lost in the hole; however, there are several other reasons for sidetracking. A sidetrack can be performed so the bottom of the hole can intersect a producing formation at a more favorable position such as up dip above the oil-water contact. A well can be sidetracked to alleviate problems associated with water or gas coning. A sidetrack can be performed in an old well to move the location of the bottom of the hole from a depleted portion of the reservoir to a portion that is productive, such as, across a fault or permeability barrier. 

Most often, a sidetrack is accomplished by setting a cement plug in the hole and dressing off the plug to a depth at which the sidetrack will commence. The sidetrack can be either "blind" or "oriented". In a blind sidetrack, the direction of the sidetrack is not specified and is not considered a directional well. In either case, a deflecting tool is used to drill out the old hole and start a new hole.

2. Straight Hole Drilling
straight hole drilling may be a special case of directional drilling where an try is made out to keep the hole vertical. a few reasons for wanting out to keep the hole vertical are :
a. out to keep from crossing lease lines ;
b. out to keep among the specifications of the drilling contract ;
c. out to keep among the well spacing requirements because we are part of a developed field 

3. Controlled Directional Drilling

Controlled directional drilling is used when drilling multiple wells from an artificial structure such as offshore platforms, drilling pads, or man made islands. The economics of building one offshore platform for each well would be prohibitive in most cases. However, since wells can be directionally drilled, forty or more wells can be drilled from a single platform. Without controlled directional drilling, most offshore drilling would not be economical.

 

4. Drilling Multiple Sands With One Wellbore
there will be special cases when multiple sands are drilled with one wellbore. where steeply dipping sand zones are sealed by an unconformity, fault, or salt dome overhang, variety of vertical wells might possibly be needed to actually manufacture every sand, which you ll realize are separated by a permeability barrier. in spite of this, all the sand zones often is penetrated with one directionally drilled well thereby greatly reducing the price of production 

5. Inaccessible Locations there will be occasions when oil deposits lie beneath inaccessible locations inclusive of towns, rivers, shorelines, mountains, or maybe even production facilities. each time a location can't be constructed directly higher than the manufacturing formation, the wellbore often is horizontally displaced by directional drilling. this allows production associated with an otherwise inaccessible hydrocarbon deposit  

6. Fault Drilling
directional drilling can be applicable in fault drilling. it is typically troublesome to actually drill a vertical well because we are part of a steeply dipping, inclined fault plane. usually, the bit can deflect when passing in the fault plane, and typically the bit can follow the fault plane. to actually avoid the challenge, the well often is drilled upon the upthrown or downthrown side on your fault and deflected into your manufacturing formation. the bit can cross the fault at enough associated with an angle exactly where the direction on your bit can't amendment to actually follow the fault. 

7. Drilling Salt Dome Region several oil fields are associated when using the intrusion of salt domes. directional drilling has also been utilized tap a number of oil that has also been trapped by your intrusion on your salt. rather than drilling in the salt overhangs, the wells often is directionally drilled adjacent towards the salt dome and into your underlying traps as shown in figure below. in spite of this, since the event of salt saturated and oil based mostly muds, the level of directional drilling has decreased. it's troublesome to actually drill long intervals of salt with recent water muds. directionally drilling along the salt, alleviates a great deal of the issues related to drilling salt.  

8. Relief Well
a highly specialized application for directional drilling is that the relief well. if a well blows out and is not accessible direct from surface, then a relief well is drilled to actually intersect the uncontrolled well close to the bottom. water or mud are then pumped in the relief well and into your uncontrolled well. since it is typically needed that the relief well intersect the uncontrolled well, the directional drilling has to actually be extremely precise and needs special tools. survey data isn't correct enough to actually intersect a wellbore at depth. proximity logging is needed when drilling relief wells. 

9. DRILLING HORIZONTAL WELLS

Horizontal drilling is another special application of directional drilling and is used to increase the productivity of various formations. One of the first applications for horizontal drilling was in vertically fractured reservoirs. In fractured reservoirs, a significant quantity of the production comes from fractures. Unless a vertical well encounters a fracture system, production rates will be low.

Horizontal drilling is used to produce thin oil zones with water or gas coning problems. The horizontal well is optimally placed in the oil leg of the reservoir. The oil can then be produced at high rates with much less pressure drawdown because of the amount of formation exposed to the wellbore.
Horizontal wells are used to increase productivity from low permeability reservoirs by increasing the amount of formation exposed to the wellbore. Additionally, numerous hydraulic fractures can be placed along a single wellbore to increase production and reduce the number of vertical wells required to drain the reservoir.

Horizontal wells can be used to maximize production from reservoirs which are not being efficiently drained by vertical wells.

10. Drilling Multilateral Wells

Directional drilling can also be used to drill multilateral wells. Multilaterals are additional wells drilled from a parent wellbore. Multilaterals can be as simple as an open hole sidetrack or it can be more complicated with a junction that is cased and has pressure isolation and reentry capabilities. Multilaterals are used where production can be incrementally increased with less capital costs. Multilaterals can be used offshore where the number of slots are limited. It is also used to place additional horizontal wells in a reservoir.

11. Extended Reach Drilling
Another application of directional drilling is what is commonly termed extended reach drilling. As illustrated in Figure below, extended reach drilling is where wells have high inclinations and large horizontal displacements for the true vertical depth drilled. Extended reach drilling is used to develop reservoirs with fewer platforms or smaller sections of a reservoir where an additional platform cannot be economically justified. Extended reach drilling will become more popular as the cost of platforms in deeper water and severe environments becomes more expensive.

20. KICK OFF PROCEDURE FOR DIRECTIONAL WELLS

Dedicated to : Mr. APS Gill, Mr. Munir Alam, Mr. S Suman & Mr. Chandrashekhar Mallik , Directional Drilling Team, ONGC Limited, Mehsana Asset, INDIA                       

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In directional wells we usually drill vertically upto the kick-off point (KOP).

From the KOP the well is deflected towards the target.

While planning a directional well we determine an angle and a direction in which the well is to be kicked off.

I hereby furnish my experience of kick off operation gained at a Horizontal directional well at Location No. :SNHK, drilled at Santhal Oil Field, Cambay Basin of Western Onshore, India.

Operator: Oil and Natural Gas Corporation Ltd., India

Directional Drilling Service Provider: M/s Weatherford Oil Tool Middle East Ltd.

Fig 20.1 General Well Data

 Note: The Excel sheet has been manually developed by Deepak Choudhary for Academic Purpose.

Fig 20.2 Kick off String Assembly

Note: The Excel sheet has been manually developed by Deepak Choudhary for Project Report Purpose.

 

Operation Report :

M/Arrangement & R/I with above BHA along with MWD tool assembly upto 661.50 m against planned 687.00 m. 

Circulated to condition mud at 661.5 m. 

Stopped circulation and conducted survey at bottom keeping the string in satic condition. 

The survey reading gives us the value of inclination, azimuth and toolface.

It should be noted that for angle less than 3 or 5 degree, the tool gives us MAGNETIC TOOL FACE.

These survey readings are displayed on the MWD Rig Floor Display Unit and looks like shown in figure below:

Fig 20.3 MTF indication at MWD Rig Floor Display Unit

Now after the survey is conducted, we observed that that MTF is 40 degree.

It is to be noted at the MTF and Azimuth are same, i.e. wrt true North. So by adjusting the MTF we can kick of the well at our required azimuth which is 189 degree.

So in order to bring MTF to 189 degree, the scribe line of the motor should be rotated by an angle of 149 degree (= 189 - 40)  towards right (clock-wise).

Once the required toolface setting has been determined (i.e. 149 degree), the effect of reactive torque must be considered.

Reactive torque is the twisting effect caused by the stator of the downhole motor turning anticlockwise in response to the rotor turning clockwise.

The amount of twisting depends on the physical properties of the motor, the length of the drill string and the formation characteristics. 

Motor manufacturers provide estimates of how much left-hand turn can be expected under certain situations. From these tables, or from experience of drilling with similar tools in similar formations, the directional driller must compensate for reactive torque by deliberately pointing the tool face to the right of the calculated heading.

As soon as the bit begins to drill, the scribe line will turn to the left to bring it
back to the calculated heading. The amount of WOB will also affect the reactive torque. As the bit drills off, the reactive torque will reduce.

In our case, the result of reactive torque was estimated to be about 20 degree.

So, net right turn to be provided = MTF Correction (149)+Reactive torque (20) 

Thus to make a 149 degree incriment in MTF, we need to rotate the whole system by 169 degree right (i.e. clockwise).

Now we take into consideration the Bit walk. Bit walk is the tendency of the bit to wander off course by following the direction of rotation (usually to the right). 

Let us consider 10 degree as a correction factor to maintain the deviation tendency due to bit walk.

So now from 169 degree we have to reduce 10 degree to adjust the bit walk tendency.

Finally, we are left with 159 degree.

To do so, we make a reference marking on rotary table and other marking which is 159 degree to right of rotory table marking on the floor using chalk.

Note: the two markings should be visible to the driller as he is the one who is going to rotate the rotary table.

The marking made on the rotary table is as shown in the picture below :

Fig 20.4 Tool face Correction

 Now, by rotating the rotary table in clock wise fashion, we will coincide the two markings so that the whole system rotates by 159 degree right.

After the two markings coincide, it looks something like as shown in the figure below :

Fig 20.5 Tool face Correction

 After the markings coincide, we look at the MWD Rig Floor Display unit which keeps updating the tool face every 30 seconds.

Now the situation is that, the string is stationary and we are waiting for the tool face to be updated on Rig floor display unit.

We want the rig floor display unit to show the MTF to be equal to 179 degree exact wrt North (N). 

It is to be noted that the reactive torque may vary. The data provided my Mud motor manufacturers and the estimate made by the directional driller are not always an exact data. It's an estimated one. So there might be some positive or negative error in the MTF reading which we are waiting for.

So the wait is over ... Here comes the updated tool face reading :

Fig 20.6 MWD Rig Floor Display Unit showing the corrected MTF

The actual reading of 175 degree is practically obtained which is 4 degree less than the desired 179 degree.

We have a scope to correct this 4 degree difference in azimuth over the remaining course length. Therefore this difference of azimuth is not a harmful issue. It is suggested that there is no harm if kick off is performed at 175 degree azimuth and later correction may suitably be made for the said 4 degree.

KICK OFF TECHNIQUE

Now to kick off the well with azimuth = 175 degree, we lock the rotary table so that there is no rotational movement provided to the drill string which may disturb its tool face orientation.

The drilling is now performed by the mud motor, not by the kelly. At the derrick floor the whole system is stationary and the mud motor performs its drilling job at the bottom.

From the surface we continuously keep maintaining the desired WOB so that the further drilling by mud motor is continued. This process of drilling using mud motor by keeping the rotary table in locked condition is called SLIDING.

During kick off, our main motive is to initially provide a guided path to the BHA. Now what length to slide will depend on the type of formation being drilled.

In prevailing practice, slide in one stretch is done for 10-12m of MD. The decision of the length to be slided depends upon the consolidation of the formation being drilled. 

In loose formation there is more risk of deviation, so the slide length is taken more than 2 drill pipe length. 

In hard formation the deviation tendency is less, so even a single drill pipe length of slide is sufficient to guide the bit in a particular path.

The kick off operation is now over.

Based on his experience, the Directional Driller will decide to take further sliding or to switch over to rotary drilling.

Fig 20.7 Sliding using Mud Motor (Left) and Rotary Drilling (Right)

Now our next objective is to check the result of our slide. It is to be noted that the MWD tool lies at about 20 m above the bit. This distance b/w the MWD tool and the Bit is called the tool offset. After we have slided for say 12 m, the drilled depth is 661.5+12 =673.5 m. The position of bit is now at 673.5 m and the MWD tool is 20 m above the bit, i.e. at 653.5 m.

When the drilled depth will be 673.5+20=693.5 m, the position of MWD tool will be at the end of slide, i.e., at 673.5 m.

Now we can take survey to check the result of our sliding action.

Survey Procedure :

- Stop Rotary.

- Bring String 3-4 m off bottom.

- Circulate out cuttings.

- Shut off pump and confirm that Pump Down Time at MWD Rig Floor Display  unit declines to zero. It indicates that the pump discharge is zero.

- Now concentrate at Pump Up Time at MWD Rig Floor Display unit. It keeps on increasing which indicates the time for which the pump had been kept shut off (no discharge observed). 

- It is worth mentioning that it takes about 2 -3 minutes for the display of survey data at MWD Rig Floor Display unit.

- Record the Survey data.

The case data is furnished as below :

Fig 20.6 Survey Sheet

Note: The Excel sheet has been manually developed by Deepak Choudhary for Project Report Purpose.

In the table, the survey readings at 693.15 m MD is the result of 12 m slide. This also indicates that the slide was properly performed and has given the desired result.

END OF THE BLOG

19. Toolface : Magnetic Tool Face (MTF) , Gravity Tool Face (GTF) , Tool Face Orientation

The sensors used in steering tools and MWD/LWD tools are solid-state electronic devices known as magnetometers and accelerometers which respond to the earth's magnetic field and gravitational field respectively.
 

Since the magnetometers may be affected by the steel collars and drill pipe, the probe must be seated within non-magnetic collars. The probe slots into the muleshoe key, which is aligned with the scribe line of the bent sub. 

The probe therefore measures the direction in which the scribe line of bent sub is pointing.
 

The orientation of the bent sub can be measured relative to Magnetic North (magnetic toolface) or with respect to the High Side of the hole (gravity toolface). 

If we place a plumb bob at the centre of any section of wellbore, the plumb bob orients itself in the direction of "g", vertically downwards. The direction opposite to the orientation of plumb bob is the high side of the wellbore.

At low inclinations (0-5°) magnetic toolface is used, since the High Side is not well-defined at that stage. Once the angle increases, however, and the hole direction becomes established, the gravity toolface is used (i.e. toolface is reported as a number of degrees to the left or right of High Side). 

The High Side of the hole can be defined by the accelerometers. The High Side is directly opposite to the gravity vector, which is the sum of the three gravitational components measured by the accelerometers.
 

Now, before taking this discussion ahead, you should know what scribe line and  the tool face alignment and orientation  means.

Look at the figure below. It shows an adjustable bent sub which gives us an option to adjust the amount of bent we wish to provide to the motor. It generally ranges between 0 to 3 degrees.

Now to provide a desired bent, we hold the upper and lower ABH (Adjustable Bent Housing) using the tong and by using chain tong on orientation sleeve we coincide the upper and lower angular marking to the desired value.

 

Suppose we desire to provide 2.89 degree initial bent. So after coinciding the two angular marking, what the bent sub looks is like in the figure below :

The line passing through the two coincident angular markings give us bent sub tool face, i.e. the orientation of our bent sub. See figure below :

Now have a look at this figure:

This is how the accelerometer and the magnetometer is arranged in the MWD unit aligned  in same axis (z axis).

Typically, three magnetometers and three accelerometers are used to measure the three components of the gravity vector and the Earth magnetic field vector in the sensor frame.

The voltage outputs from the accelerometers are denoted by Gx, Gy and Gz, corresponding to the three orthogonal axes.

Similarly the magnetometer outputs are Hx, Hy and Hz.

z axis points down the axis of the tool and the y axis is defined as being in line with the toolface.

Now in order to accomplish the directional drilling task, the operator needs to know the orientation of the bent sub. The relationship between the directional sensor and the bent sub is fixed for each bottom hole assembly. From the directional sensor measurement, the directional sensor tool face is known. If the angular difference between the directional sensor reference point and the bent sub is measured on the surface, then the operator can use this measurement and the directional sensor tool face reading to determine the orientation of the bent sub, namely, the bent sub tool face. Such angular difference is sometimes called tool face offset.

In the prior art, the angular difference is determined by the use of a scribe line on the exterior of the instrument housing.

Now our next job is orient our MWD/LWD tool in the direction of bent.

Below is a typical BHA arrangement for a 8 1/2" Hole Section :

After we are done with adjusting the bent sub to a desired angle, we make up the string stabilizer, the float sub, the UBHO sub and 1 (one in number) NMDC (also called Monel). To know more about Stabilizer, Float Sub and UBHO sub refer my blog post : Stabilizer, Float Sub , UBHO Sub. 

Now out job is to lower the MWD tool assembly into the NMDC. 

The MWD tool is run inside the NMDC (Monel).

It gets seated in the mule shoe sub (UBHO Sub) which is at the bottom of NMDC.

The tool face of MWD usually doesnot remain aligned with the toolface of downhole motor.

So as to align the MWD toolface with the toolface of downhole mud motor we practise any one of the following procedure :

1

In this procedure, we get back to the time when we have made up the UBHO sub and the MWD tool has not yet been lowered.
 

The mule shoe sub has an adjustable key.

The sleeve with the key can be rotated.

The set screw is loosened and the key is alligned with the bent of the downhole mud motor.

Once the key is aligned with the bent of the motor, the set screw is tightened.

This keeps the key always aligned with the bend provided to the motor.

Now the orientation of mule shoe is same as that of the motor bend.

The MWD tool is run into the NMDC.

The tool has a mule shoe stinger on it.

The stinger has a slot and the mule shoe sleeve has a key.

When the mule shoe stinger enters the mule shoe sub, it is rotated until it gets lined up with the orientation of the mule shoe sub and the motor.

This happens when the slot of the stinger gets seated in key of the UBHO sub.

Note : The survey tool can easily be manually rotated until the tool is aligned with the key.

Thus now the tool face shown by the MWD tool is also the tool face of the bend of the down hole motor.

UBHO Sub

2

In this procedure, we are at the situation when we have lowered the MWD tool in the NMDC and the stinger's slot has got seated in the UBHO sleeve's key.
 

The scribe line at the mule shoe key indicates the tool face of the MWD tool.

The scribe line at bend of the downhole motor indicates the toolface of the bent of the motor.

Now we check that the two scribe lines (one of the motor and other of the surveying tool i.e. MWD here) are aligned or not.

At present condition, we have the following arrangement hanging fron the elevator from top to bottom: NMDC - UBHO Sub - String Stab - Mud Motor - Bit.

We lower the present made assembly until UBHO Sub is on man height.

At the key of the UBHO sub (i.e. on the scribe line), we make any marking like placing a chalk piece or any pointed visible object which shows us the position of the scribe line/ the UBHO key. Some people tape a laser pointing downwards.

Now we lift the made assembly upwards using elevator until we have our bent sub at the man height.

We apply slip to make the assembly stationary.

Now we look up at our placed marking on the UBHO sub and find its position relative to the bend sub scribe line. (For this, the operator stands closer to the bent sub, looks upward to the made marking and tries to make an imaginary line from the marking to the bent.

If the two scribe lines are aligned, then no issues. We are done with our job.

But, if the two scribe lines are not alligned, then we measure the offset tool face (OTF) between the two scribe lines using the protector, which gives and angular value of the offset.

This offset tool face (OTF) is a correction factor.

Now, the operator must decide whether to add or subtract this angular difference to the directional sensor tool face for purposes of determining the orientation of the bent sub. Obviously, the decision as to whether to add or subtract the angular difference is critical. Operators are trained to follow a procedure to correctly determine whether the angular difference should be input into the surface computer as a positive or negative number to be added to the tool face reading to obtain the bent sub orientation. 

Refer figure below which clearly describes the above procedure : 

  

 Geometrically, we can explain the offset angle as shown in figure below :

CORRECTIONS

Offset Correction aligns accelerometer toolface with toolface of bent sub.

Magnetic Declination correction corrects the magnetometer error.

In the picture below, I have tried to explain how the axis of the accelerometer actually behaves and helps determining the inclination, using the help of a hand made rough model.

INCLINATION

The inclination is the angle measured from vertical to the axis of the Z accelerometer.

The inclination can be determined from the above model and comes out to be :

tan α  = ( G_x² + G_y² )^1/2 / G_z .

TOOLFACE 

Magnetic Tool Face

It is the direction, in the horizontal plane, the bent sub scribe line is pointing with regard to the north reference (Grid, Mag, or True). 

Magnetic orientation is used when the inclination of the well bore is less than 5°. When the inclination is below this amount, the survey instrument cannot accurately determine the highside of the instrument for orientation purposes. The toolface will be presented in azimuth or quadrant form, referenced to magnetic north. The magnetic toolface reading is whatever magnetic direction the toolface is pointed. 

Gravity Tool Face

It is the angular distance that a bent sub scribe line is turned, about the tool axis, relative to the high side of the hole. 

If the inclination of the well bore is above 5° to 8°, then the gravity toolface can be used. 

The toolface will be referenced to the highside of the survey instrument, no matter what the hole direction of the survey instrument is at the time. 

The toolface will be presented in a number of degrees either right or left of the highside. 

GTF orientation is represented by figure below :

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18. STABILIZERS

Stabilizers are an indispensable part of almost all rotary directional BHAs. 

Near-bit stabilizers have BOX x BOX connections. They are usually bored out to accept a float valve. 

String stabilizers have PIN x BOX connections. 

Most stabilizers have a right-hand spiral.

Stabilizers are used to:

Control hole deviation.

Reduce the risk of differential sticking.

Ream out doglegs and keyseats.

Here we are going to discuss the following types of stabilizer :

Integral Blade Stabilizers

Welded Blade Stabilizers

Sleeve Type Stabilizers 

Clamp-on Stabilizers

Non-Rotating Stabilizers

INTEGRAL BLADE STABILIZERS (IB)

I.B. stabilizers are made from high-strength alloy steel as a single piece tool. They are rolled and machined to provide the blades.

The unitized construction features three spiraled ribs designed to minimize down hole torque, reduce damage to the hole wall and ensure maximum fluid circulation. 

The IBS is well suited for use in most formations from soft and sticky to hard and abrasive. 

It is available in both bottom-hole and string designs, providing the flexibility to run it anywhere in the BHA.

When the blades wear down to an unacceptable diameter, the tool should be removed from the drilling assembly and returned for servicing where it can usually be redressed to full gauge size. 

They can have either three or four blades. 

I.B. stabilizers normally have tungsten carbide inserts (TCIs). Pressed-in TCIs are recommended in abrasive
formations.

Features and Benifits :

The blades are an integral part of the tool body, eliminating the risk of leaving components or pieces in the hole.

Available in both “open” and “full wrap” designs, providing optimum hole wall contact while ensuring maximum fluid bypass area.

Application in Directional Drilling :

A packed hole assembly typically requires the placement of multiple IB stabilizers throughout the three zones of stabilization. Contact a OTI - representative for BHA recommendations.

A pendulum assembly is a recommended application for the IBS due to its unitized design. For the most effective pendulum assembly, two stabilizers should be run separated by one drill collar.

Vibration and drill collar whip can be reduced through the placement of stabilizers in the BHA and upper drill collar string.

Extended Life IBS Specification :

Standard IBS Specification :

WELDED BLADE STABILIZERS (WBS) :

The Welded Blade Stabilizers used in the B.H.A for drilling soft to medium hard formation holes are available in three types (straight, straight-offset or spiral design).

They are best suited to large hole sizes where the formation is softer because they allow maximum flow rates to be used.

Stabilizer bodies are manufactured from AISI 4145 H Modified Steel with mechanical properties in accordance with API Specification 7.

Mid steel blades are welded onto the body using strictly controlled pre-heating, post weld heat treatment and weld application techniques.

All areas affected by the process of welding are subject to full non-destructive examination to assure the mechanical integrity of the joint.

Standard Welded  Blade Stabilizers are available in 3 or 4 blade configuration with the spiral type available with open or tight spiral.

HF 1000 or HF 2000 Hardfacings are most commonly applied to Welded Blade Stabilizers.

Standard dimension of WBS :

Welded blade stabilizers are available in following three configurations: 

NOTE : IBS are more expensive than welded blade type stabilizers, since they are machined from one piece of metal.

SLEEVE TYPE STABILIZERS :

These consist of replaceable sleeves that are mounted on the stabilizer body. They offer the advantage of changing out a sleeve with worn blades or replacing it with one of another gauge size. The blades can be dressed with tungsten carbide inserts for abrasive formations.

Sleeves :

There are two main designs of sleeve-type stabilizer as shown in figure below:

Two-piece stabilizer (mandrel and sleeve):

The sleeve is screwed onto the coarse threads on the outside of the mandrel and torqued up to the recommended value. 

Sleeve makeup torque is low. 

There is no pressure seal at the sleeve. 

It is convenient to change sleeves on the drill floor. 

This design of stabilizer is manufactured by several companies. 

It is in wide use today.

Three-piece stabilizer (mandrel, sleeve and saver sub):

The sleeve is screwed onto the mandrel first, by hand. 

The saver sub is then screwed into the mandrel and this connection is torqued up to the recommended value. 

In this case, there is a mud pressure seal at the mandrel/saver sub connection. Makeup torque of this connection is the full value for that size of API connection. 

Great care must be taken (clean and dope the shoulders properly, use correct makeup torque), otherwise downhole washouts etc. will result. 

It can be quite difficult any time-consuming to change/service the sleeve. For these reasons, this design of sleeve-type stabilizer is not as widely used today as it was some years ago.

CLAMP-ON STABILIZER

Clamp-on stabilizers allow more flexibility in BHA design. 

They can be positioned on NMDCs, MWD, PDMs etc. at the required spacing to maintain directional control. 

Nonmagnetic clamp-on stabilizers are available on request Some clients are apprehensive about running clamp-on because of the danger of them moving position downhole. Sometimes they’re difficult to take off after POOH.

NON- ROTATING STABILIZER

These stabilizers are used to centralize the drill collars, but the rubber sleeve allows the string to rotate while the sleeve remains stationary. The wear on the blades is therefore much less than in other stabilizers and so they can be used in harder formations.

Stabilizers can be installed just above the bit (near-bit stabilizers) or at any point within the BHA (string stabilizers). 

Two stabilizers can also be run in tandem if necessary ("piggy-back"). Stabilizers are inserted at drill collar connections. This limits their spacing to 30 ft or multiples of 30 ft.
 

Closer spacing can be achieved by using shorter drill collars (pony collars) that are 10-15 ft long. 

"Clamp on" stabilizers can be used to provide support at some point along the length of a collar. 

Any stabilizer that is placed near a magnetic surveying tool must be made of non-magnetic material, to prevent distortion of the survey results.

 

HARDFACINGS :

Hardfacing is a metalworking process where harder or tougher material is applied to a base metal. It is welded to the base material, and is generally takes the form of specialized electrodes for arc welding or filler rod for oxyacetylene and TIG welding.

Hardfacing may be applied to a new part during production to increase its wear resistance, or it may be used to restore a worn-down surface.

HF 1000

Crushed tungsten carbide held in a nickel bronze matrix. The 3mm grain size ensures greater concentration of carbide which is ideal for soft formation drilling.

HF 2000

Trapezoidal tungsten carbide inserts held in a sintered carbide nickel bronze matrix. This will give a greater depth of carbide coverage – ideal for high deviation drilling in abrasive formations.

HF 3000

Tungsten carbide inserts set in a powder spray deposit ideal for abrasive formations. 97% bonding guaranteed, certified by ultrasonic report. Recommended for non-magnetic stabilizers.

HF 4000

Tungsten carbide inserts (button type). The inserts have been developed to allow cold insertion and maintain close fit. A greater concentration of inserts on the bottom third of the blade and leading edge will increase surface contact to reduce wear in highly abrasive formations.

HF 5000

This oxy-acetylene process applies tough molten carbide particles of varying sizes held in a nickel chrome matrix which provides excellent bonding properties and greater surface wear characteristics are achieved. Surface hardness levels over 40 HRC. Ideal for GEO-THERMAL applications over 350°.

HF 5000

This process is a highly automated way of applying hardface and utilizes a combined arc/plasma stream on the work piece surface. This results a low base metal dilution and a dense, uniform coating, the filling medium can be variety of hardfacing consumables.

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