TT Coil Setup

Section 8:
Directional Drilling Systems
Surface Location Systems
8.0 Surface Location Systems

The surface locators comprise a transmitter placed in a sub located behind the bit or the motor. The instrument transmits roll angle and pitch to a hand held receiver on surface. The surface receiver is moved to a position of the highest signal strength and the position is flagged. Depth capability is determined by one of two methods, ie. a. Signal Strength b. Triangulation by a dual antenna system. Some locators now are able to transmit the roll and pitch back to a Drillers Display via VHF radio. Existing now are a number of different locator systems from various companies. Their specified search depths are continuing to increase. Their signal processing circuits are becoming more sophisticated. 8.1 Weaknesses All surface locators have similar problems. 1. EM ( Electromagnetic Transmission ), is used to transmit the data from the instrument to the surface receiver. EM transmission is defined as VLF ( Very Low Frequency ) radio transmissions. EM is the only radio transmission method able to propagate a signal through the earth due to its VLF signal. Everything generating, carrying or using electricity generates electromagnetic radiation at various frequencies. DC current generates the largest radiations. Most of the surrounding EM radiations will interfere with the signal from a downhole transmitter. If the surrounding EM radiations are generated from AC current, the signal strength from the transmitter will be affected most radically. If the surrounding EM radiations are generated from a DC source, the signal strength may be affected only marginally BUT the actual located position will be affected radically. The answer therefore to a high local EM field strength in some areas is to increase the signal strength of the transmitter and refine the discrimination circuits of the receiver. This has been and is continuing to be done. In the field, since most downhole transmitters from different manufacturers transmit their signal using different frequencies, it is sometimes possible to change to another manufacturers transmitter that may not be affected by the local EM radiated frequencies. The answer to high local DC generated field strengths, is to change to another method of guidance.
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2. Battery Life is a major problem for all systems. Most instruments have sleep circuits in an effort to conserve battery life but since VLF transmission requires significant power, downhole time is limited. Some systems now have the capability to run with wirelines in order to increase signal strength and not depend on batteries. 3. Pitch ( Inclination ) is transmitted in Percent of Grade which lends itself to guidance by topography rather than by plan. The result is generally a high number of doglegs impacting the rigs ability to finish longer jobs. 4. Roll ( High Side ) is inaccurate in relation to actual angle. It is in most instruments readable to within 10 to 15 Degrees. This results again in high dog legs on a drilled joint to joint basis. 8.2 Strengths 1. Most locator systems have a price tag less than $ 10,000.00. The downhole instrument runs between $ 3 - 5000.00 2. Operating instructions are easily learned and quickly understood although drilling technique is not. 3. Wireless transmission means that drilling rates are extremely fast. 8.3 Conclusions There is a place for all locator systems due primarily to the low capital cost and production rates achievable. They will be utilized on the small and mini rigs where search depths are shallow, ie. 30 - 40 feet. They may be used in conjunction with wireline tools in special cases. Added caution should be used if the product line is steel due to their proclivity to produce dog legs.
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Section 9:
Land Survey Techniques
9.0 Land Survey Techniques

The purpose of this section is to familiarize our field engineers with some different types of land survey instruments and some procedures needed to collect and document survey data. 9.1 Instrument Set-Up When setting up an instrument with four leveling screws, place the instrument over the known point and rotate the scope so it is directly over two of the leveling screws. Center the base plate bubble using one or both of these screws. Once this is done rotate the scope 90 Degrees so that the scope is directly over the remaining two leveling screws. Center the bubble moving one or both of these leveling screws. Rotate the scope over the first two leveling screws to insure the instrument is still level. If the instrument is not directly over the known point, evidenced by the plumb bob or optical plumb, loosen all four screws and slide the head over the point. Follow the above procedure until the instrument is over the point and level. When setting up an instrument with three leveling screws rotate scope directly over one of the leveling screws and adjust so the bubble is centered. Rotate the scope 90 Degrees so it is adjacent to the first leveling screw. To center the bubble, adjust the remaining two leveling screws at the same time in opposite directions. Recheck the first position to insure it is still level. To set up a instrument with optical plumb and adjustable legs, look through the optical plumb lens while placing the legs on the ground. Ensure the target is on the point to be occupied. At this time it is not important for the base of the tripod to be level. Adjust the legs one at a time to move the bubble close to the center, then follow the above steps to fine level the instrument. 9.2 Turning and Reading Angles This is a difficult topic to write about due to the many different types of instruments and scales. Basically there are two types of instruments, transits and theodolites. Transits are generally less expensive and less accurate, but will serve our purpose. You read the angle on a vernier scale on the outside of the instrument using a magnifying glass. The outside plate of the scale is divided into 360 in 1/2 Degree increments or possibly 1/3 Degree increments. The inside plate of the scale is divided into twenty or thirty minute marks, both directions from a 0 line. To set 0, loosen the outer scale grub screw to allow the outer scale to rotate with the inner scale. Line the 0 mark on the outside scale to the 0 line on the inside scale. The first line right and left of the inside scale should be slightly inside that of the first line right and left of the 0 line on the outside scale. Once set, fix the outer scale to the instrument by tightening its respective screw.
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To turn the angle sight to Point A and note the angle in degree and minutes. Turn the leveled instrument to point B and note the angle. Subtract one from the other to determine the angular difference. To read an angle on a theodolite, the angle is seen in the small scope on the side of the main scope. Most theodolites have a micrometer scale. You turn the micrometer dial to center the stationary line between the two rotating lines and add the values together. 9.3 Measuring Distances Shooting stadia is the best way to determine a distance across a river or other obstacle that can not be taped. Stadia are the two horizontal lines intersecting the vertical crosshair above and below the center cross hair. To shoot stadia, set up on a known point and look at the level rod positioned at the point to which you need a distance. Move the scope up or down to position the bottom cross hair on a even foot mark on the level rod. Read the top cross hair subtract the top reading from the bottom, multiply the difference by 100 to obtain the distance. To shoot a distance by turning an angle you physically measure with a tape (at right angles to the line to be measured) to a second target, and note the distance. Set the instrument up on a known point and turn an angle between the two points. Use the following formula to derive the distance. Measured Length TAN Angle
Distance
Where extreme accuracy is desired, turn the angle three separate times, from different starting points. Take care in reading and noting each. Add the three results and divide by three. This will produce an average and take out some instrument and human error potential.
9.4 Shooting Elevations The best instrument to use for elevations is one made for the job, ie. a Level. The reason is because the cross hairs in the scope float perpendicular to gravity therefore taking out potential operator induced error related to leveling a transit or theodolite. Transits and theodolites are acceptable alternatives and can be used with confidence, given proper set up procedures. The instrument does not need to be set on a known point to shoot elevations. It does need to be leveled accurately and checked for level prior to each elevation shot. If you set up on the entry point, use the range rod and measure from the scope to the ground. This gives you the instrument height, ( HI ). Subtracting all other readings from this height, will give you relative elevations referenced to the entry point.
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Construct a table as follows. The completed table should look something like this. Elevation Chart Shot No. 1 2 3 4 5 6 7 8 9 10 11 12 Relative Elev. Diff. 4.3 -0.5 -0.7 -0.9 -6.0 -6.3 -6.1 0.0 +2.8 -1.0 0.0 Datum Elev. 276.8 272.0 271.8 271.6 266.5 266.2 266.4 272.5 275.3 271.5 276.8
(+) 4.3
HI
(-)
Elevation 0.0 4.8 5.0 5.2 10.3 10.6 10.4 4.3 5.3 4.3
Description Entry Point Coil Pt 1 Coil Pt 2 High Bank Coil Pt 3 Toe of Slope CP 4 Edge of Water CP 5 CP6 Edge of Hill CP7 Top of Hill CP 8 Near Hill CP 9 CP 10
1.5
Entry Point Datum = 272.5
It is important to keep track of exactly where each elevation shot is located in reference to your known point. Keeping a table similar to the above gives you a logical record of all shots and their location. The description should reference both your projected coil corner positions as well as Topo reference. Once the table is established, and all relative differences established by subtracting stick reading from the HI, you have established the coil elevations referenced to the entry point. If you need to relate the elevations back to a datum reference, ie. entry point real elevation is 272.5, then add each elevation difference to the real elevation datum at the known point. If you have not set up on the entry point, you will need to shoot the entry point and use the stick reading as the HI. Follow the steps in the same manner. 9.5 Note Keeping It is imperative you keep all field notes in the job file. Hand written notes, kept in an organized manner, will save both you and the office innumerable headaches.
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10.0 Job Site Actions Pilot Hole

The Single Most Important Job Function during the Set Up of a Job is ESTABLISHING THE INITIAL LINE AZIMUTH Failure to spend the time to do this accurately, will normally result in at least one pull back on the exit side resulting in lost time. It will definitely result in a course change within the TruTrack Coil on the exit side. This can cause excess friction during pull back of the product line. Most of the job of the Engineer responsible for guidance, is based on good logical observation skills and the application of practical methodology. This section covers basic actions required of the directional drilling engineer to successfully complete a pilot hole. 10.1 Arrival On arrival, after introductions, the engineer should look at the job in overview. This is normally the last time you will have the opportunity to do this. Once begun, you will be concentrating on solving problems of detail during the job, with no time to sit back and think of the overall project.
10.1.1 Walk the Line Both Sides
Be observant as you walk. Make notes of future potential magnetic problems and their locations. Discuss with the customer what he wants to achieve and in what time frame. Find out if there are any underground services. Note their location. Plan your set up of TruTrack coils as you walk. Determine if this is a straightforward setup or if you will need any special equipment. Discuss the needs now with the customer. Find out the limits of the crossing path. What cover is required? What is the ground formation to be drilled? Are problems expected? Where? Determine where you will do a probe shoot based upon observation. Study the topography with a view to how you will shoot centerlines and lay out TruTrack. Finally, determine from the customer, how much time do you have to get rigged up and ready to spud. Fully discuss with him any problems you have observed and advise him of how much time you will need. Ask for assistance where required.
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10.1.2 Unload and Check Equipment
After walking the line, before anything else, unload your equipment. Take Intrerface, Readout, Computer, Printer, power supplies, cables etc. and set out in their locations. Make up Probe in its housing and set aside. Make sure you have everything with you that you will need for the job. You do not want to spend the morning rigging up TruTrack and then finding you forgot to bring a Probe!! Check your equipment now!
10.1.3 Customer Documentation
Obtain from the customer, ALL of his site plans. He may have soil survey data, profile information, station planning, topo maps, engineering company data, etc. Do this on arrival and study the plans. Relate the plans to your actual location. Most of the time (95%) the data will not exactly match the actual location. Look for differences and discuss what you find with the customer. 10.2 TruTrack Layout Having walked the line and studied the plans, you will have a clear idea of how to proceed with the TruTrack layout. Study the TruTrack Operations Manual in Section 14 for general methodology. The following points should be used where possible conflicts or clarity problems exist. Lay wire, ready for spud on the entry side and if possible, set corner stakes on the exit side ready for wire.
10.2.1 Width
From the drilling plan, locate the total elevation change between the entry point elevation and the proposed depth at the end of the entry coil. The width of the coil at the deepest point of the bore should be about 5% wider than the depth. The extra width will take into account the fact that you might lose angle while drilling the entry curve and be deeper at the end of the coil. Additionally, after the coils have been laid, and during the job, the customer might wish to replan to a deeper point. Finally, if drilling deeper than the coil width, radial intensities decrease rapidly and sometimes the field will flip. This occurs often in this case. Always make the coil 5% or more wider than planned depth.
10.2.2 Length
Make the coils length as long as required within the limits of good strong measured fields. A coil of 1000 at 60 of depth will work where an elevation of 80 might not yield a strong enough radial intensity.
10.2.3 Wire
Use insulated 8 AWG or (10mm)squared stranded wire. Make strong splices which will not pull apart. Insulate with rubber bonding tape and cover with electrical vinyl tape.
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10.2.4 Corners
Number the corners in a clockwise manner starting from the corner where you plan to set the power source. ( Welding Machine) Ensure that any deviation in wire direction or elevation begins and ends at a peg or stake. Do not allow the wire to curve. Make the segments straight. Shoot a centerline from entry to exit and place centerline stakes perpendicular to each corner. Use of a Right Angle Surveyors Prism is recommended. Place centerline stakes perpendicular to any obstructions you noted when you walked the line. Measure their distance from entry and note the measurements on the coil data sheet. Measure the distance from centerline left or right to the obstruction. From Entry point, using a tape measure, measure the Horizontal Distance to each centerline stake and note the distances. Against each centerline distance, measure the left/right distance to its representative coil stake. There is only one additional measurement topo elevations. Check on progress of the rig crew in getting ready to spud! Discuss with the customer your own progress.
10.2.5 Elevations
From Section 9.0 Land Survey Techniques, you will understand the basics required to shoot elevations. Make sure you do this accurately as corner elevation inaccuracy will affect TruTrack readings significantly.
10.2.6 Line Sags
If you are building an unsupported coil segment across a river or canal, you will need to deal with line sag. You must ensure that any splices in the segment must be able to survive the pulling forces required to tighten the wire and support its own weight. If the ground elevation on each side is the same, the process of developing measurements is relatively easy. The lowest point of the sag will occur exactly in the middle of the segment. If you have constructed both the left and right sides parallel, the away distance can be derived only once and used for both sides. If not parallel, you will need to plot on graph paper the centerline and both sides to scale. Using a right angle triangle, scale the center of each side against the centerline and use this for its away distance. You must then scale the left or right distance of the lowest point of the sag to the centerline. Finally, you must determine the amount of the sag. If a boat is available, use it to physically measure the lowest point. Again, if both sides are the same elevation, this is easy. Measure the distance of the wire from the water and relate this to the distance of each side to the water. Subtracting one from the other yields the line sag elevation.
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If the elevations are different on each side, you must again use graph paper and draw the stake elevations on each side to scale. Measure the elevation of the water and plot it against the sides. Finally measure the lowest point of the line sag to the water and plot it. This will be the elevation of the line sag. Measure both the left and right side every time. Ensure that this Phantom Corner is accurately noted in the proper sequence on the TruTrack Coil Data Sheet.
10.2.7 Coil Shapes
A TruTrack coil should be longer than its width! The most accurate coils seem to be rectangles. Try to attain a rectangle where possible. On the entry and exit, you may taper the beginning and end back to the entry and exit points ensuring always that it remains wider than its depth. Generally, a coil can attain any shape as long as it roughly appears to be a rectangle. Zig Zags in the sides over a short distance should be avoided at all costs. If the surface topo requires this, consider setting out two coils. Otherwise, do not believe your readings within 50 of the zig zag. The zig zag produces erroneous axial readings where the probe is not expecting them, causing errors.
10.2.8 Offset Coils
It is possible to offset the coils. Ensure measurements are very accurate and the widths are adequate to produce a strong enough field for the probe to read.
10.2.9 Testing
Once the entry side is ready, hook up the power source and make tests. Vary the current and note amperages. Refer to TruTrack program to project these amp readings against depth to ensure your coil will produce high enough radial intensities.
10.2.10 TruTrack Data Preparation
Completely fill out the TruTrack Data Sheet, NOW, while the measurements are fresh in your mind. Do not leave this step to later, since it is possible you may have forgotten a measurement! You do not want to finish rigging up the job, be ready to spud and have to tell the customer to shut down and wait while you run out and make a tape measurement on the coil you already told him was finished! 10.3 MGS Rig-Up Check on progress of the rig crew in getting ready to spud. Discuss with the customer your progress and how long you expect to need to get ready. Rig up your surface equipment and power up. Input your coil data files and make up a Survey Tabulation Sheet. Note the Coil Data File Names on the sheet in the appropriate box.
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Lay out a shoot test lead to the shoot location. Tighten the probe connections and move it to the shoot location. Connect the test lead and power the probe. Turn the probe to its high side and generally point it towards the exit point. Print screen and move the probe 10 right, still pointed towards the exit. Print screen. Note the relative positions of the probe in relation to the first check in writing on the printout. Move the probe 10 towards the exit point back on cneterline. Print screen. Move the probe 10 left of the first check and print screen. Finally, move the probe 10 closer to the rig on centerline. Print screen. You have magnetically mapped the shoot area. Make up a table as follows: Distance 90 100 100 100 110 Position CL -10 CL +10 CL H Total 48557 48530 48558 48560 48555 Dip 60.3 60.2 60.3 60.2 60.3
From looking at the H Total, you can see that the centerline shots are consistent. The only anomaly seems to be the left position. Walk around and look at the area for and cause of different magnetics. Recheck the position with the probe. Move it to a position 20 left and see if the H Total continues to drop. In the above example, the magnetics are clean and ready for the shoot. If they are not, in practice, continue testing until you locate a clean position. Ensure proper probe operation. Remove the test lead and connect it to your spare probe. Ensure proper operation. If you have time, leave a probe connected and rig up your spare Interface and spare Drillers Readout. Test them to ensure proper operation. If you do not have time now, do it later! 10.4 Profile At this point, you have a lot of data generated from the TruTrack coil layout. You must relate this to the profile provided by the customer or to the data provided. If you will be drawing the profile, now is the best time. You may wait until after the probe shoot but you take the chance of needing to change the profile if in fact the customers data is wrong. (Remember it is wrong in some way 95% of the time) On the vertical profile, draw in the surface topo and all in ground or surface obstructions you noted when you walked the line. Remember, you measured distances to each when you set up TruTrack. On the horizontal plan, draw in the obstructions in scale if possible. Ensure that the radius proposed will work for the product line to be pulled. Discuss this with the customer if the radius is too small for the line with a 4 times safety factor. If the cus98
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tomer proposes to go ahead without the safety factor, ensure you advise us by phone as soon as you can. Fax this to the office in your evening report! Make sure the profile fits the topo, the length, the cover limits and misses all in ground obstructions! If you must approach a cable or in ground line, make sure their positions are accurately known. If you have concerns, express them to the customer. Point out your concern and ALWAYS have a firm recommendation ready. You may advise the exposure of in ground services prior to spud if you must converge or pass close to any live line. Once the profile is checked and ready, set it aside. 10.5 Physical Measurements There are a number of measurements which are required to be made of the surface equipment and downhole equipment. These measurements should be made prior to the probe shoot and noted on paper.
10.5.1 Rig Measurements
A. Horizontal Distance from center of vises on the rig to the planned entry point. B. Height of the center of the vises from ground level and then to the same elevation as the entry point. C. Distance from the center of the vises to the entry point. You have now measured a right triangle. Note the measurements on paper. From the Vise Elevation and the Rig Angle, calculate the projected horizontal distance to the entry point. (Vise Elevation / Tan of Entry Angle) = Horizontal Distance from Vises to Entry Compare the calculated to your physical measurements. They should be the same. If not, find out why and discuss this with the customer. Note the difference on paper. It will produce a new physical entry point in relation to the plan. Be careful when measuring the center of the vises. Some rigs have movable front vises. You may need to establish the point of pipe break off during drilling operations and use this instead of the center of the vises. You should always check the rig angle yourself prior to spud. If a mistake was made, you need to know now, not during the confusion which always occurs while drilling the first couple of joints. Discuss your findings with the customer and what the inaccurate rig angle will cause in relation to the job.
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10.5.2 Down Hole Assembly Measurements
Now is the time to measure all drill string components of the down hole assembly. Make a list on paper of each component and note measurements, shoulder to shoulder, of each starting with the Bit or Nose of the Jet. Bit Bit Sub Motor Orientation Sub Non Mag Drill Collar Non Mag Drill Collar Drill Pipe X-Over Total DHA
10.5.3 Drill Pipe Measurements
1.2 .8 20.7 2.3 27.5 15.0 1.8 69.3
Discuss with the customer the fact that you need to know the measurements of each joint of drill pipe. Ask him to have them measured row by row as they are being used and the measurements provided to you. Find out exactly how many joints of drill pipe are on the location and make a note of it. Count them yourself! 10.6 Line Azimuth Shoot The following procedure makes the basic assumption that the Non-Magnetic Collars have already been magnetically tested back at the shop and have been found to be clean. Power up the probe to be used. Place the probe in its protective case on V Blocks or NonMagnetic Orientation Stands. Using one of the centerline TruTrack stakes about 30 - 50 from the probe position, set up the Theodolite and confirm its centerline position by sighting the entry and exit point. Using a Plumb Bob or the instruments Optic Plumb, center the instrument over the stake and level accurately. Shoot the exit point and flip to backsight. Shoot the entry point. If misaligned, move the instrument and relevel. Continue doing this until fore and back sight intersect the exit and entry point respectively. Make sure the instrument is leveled! Using the backsight, shoot the power sub on the carriage. Estimate, how much the rig is misaligned and in what direction. Note this on paper. Flip to foresight. Sight the front and rear of the probe using the vertical cross hair in the scope. Lay the cross hair alongside the probe case and continue adjusting the probe until it is exactly parallel to the cross hair. Turn the probe to its High Side.
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Recheck the centerline position by once again sighting the exit and entry points using back and foresights. Check instrument is level. Once again, check that the probe is parallel to the vertical cross hair. Now Print Screen. Turn to a tool high side of 90Degrees. Print Screen, Turn to 180 Degrees. Print Screen. Turn to 270 Degrees. Print Screen. Turn back to High Side at 0 Degrees. Print Screen. Construct the following table and set it aside for later.
Orientation 0 90 180 270 0
H Total 48560 48555 48572 48520 48555
Dip 60.3 60.2 60.3 60.1 60.3
Azimuth 27.3 27.2 27.4 27.0 27.3
Go back to the theodolite and recheck the line using fore and back sight and then recheck the probe orientation. It sometimes moves during the probe roll which would necessitate another roll set of readings. If all is OK, continue. Have the crew bring the motor, bit and orientation sub to a position about 5 on the exit side of the probe. Lay the assembly on line. . Look at the screen and check the H Total, Dip and Azimuth. If different than during the probe roll, move the motor further away by 3. Check again. Continue moving the motor away from the probe until the exact azimuth measurement noted during the probe roll is obtained. Measure the distance from the shoulder of the orientation sub to the T Slot on the probe. This is the spacing required from the top of the orientation sub to the probe in order to obtain clean magnetics during the job. Total the lengths of the two sections of non mag collars. In the example above it totals 42.5. Measure this distance from the shoulder of the orientation sub towards the rig and place a marker. Have the rig crew bring one joint of drill pipe, including the X-Over sub to this position and lay it them on line. You may need to move the theodolite! Take a Print Screen and note on the paper the readings. The H Total, Dip and Azimuth should be the same as during the roll test. If it is not, you should add an additional non-magnetic collar, until the readings match. If this is not possible, do the following. Move the motor assembly out of the way completely. Move the drill pipe towards the rig until the magnetic readings match the shoot readings. Then begin approaching the probe with
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the motor on line, until you reach the non-magnetic collar measurements. Again, in the example above, the lengths of the two non-mags was 42.5. Print Screen and note the measurements on paper. Now, repeat the probe roll and construct another table as above.
Orientation 0 90 180 270 0
H Total 48460 48455 48472 48420 48455
Dip 60.6 60.6 60.7 60.4 60.6
Azimuth 27.8 27.8 27.7 27.3 27.8
Remember, if you must drill with Z Axis interference, it is best to have the interference in front of the probe and not behind. The drill pipe has a stronger magnetic influence than the motor and can change often downhole through rotation. If the theodolite is still set up, recheck the line and the probe orientation. If not, set it up again and do it! Do not neglect this step! Always recheck that the probe has not moved once you have established a line azimuth for the job.
10.7.7 Pressure Testing
It is necessary prior to spud to pressure test the system. Push the motor or jetting assembly to the ground and engage pumps at a low rate. Establish mud flow through the jet or motor. Note on paper the pressure on the gauge at the point where the bit begins to turn. Turn off the pump and reengage. Note again where the bit begins to turn. Do this until you have a repeatable pressure to begin motor operation. Once this step is completed, increase the flow and watch the pressure. Continue increasing until you reach recommended drilling pressures for the type motor you are running. Immediately stop. In the case of the jet, establish stroke count at your projected drilling pressure. Throughout this step, you should observe the operation of the probe. Look for shorts or improper operation. Observe the rig systems to ensure proper operation.
10.7.8 Spud
You have now completed all preparation steps and are ready to spud. Leave the tool operating and advise the driller to begin pushing the bit into the ground staying on HIGH SIDE using your hand signals. GO OUTSIDE the cab near the entry point where he can see you!
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Ensure that the bit will enter the ground at the entry point without a sag in the pipe. Attempt to prop the string up until it is obvious the rig will have a straight push. Not Left/Right or sagging or too high!! Work with the crew to ensure this. Push ahead into the ground about five feet. STOP. Observe the entry point closely to once again check alignment. Physically measure the exact entry point in relation to the planned entry and note the actual numbers on paper. Go inside and observe the inclination reading on the probe. At this point you will be reading only the actual rig inclination, not the inclination on the drilling assembly in the ground. This is the reason for the extra care in spudding for a straight push. Through observation, you will be able to see easily if the motor or jet is building angle too fast. If so, pull back until the bit is just below ground and begin rotation. Rotate ahead for the same five feet and check that you have dropped angle. Continue to adjust until you have the alignment you need. Once again, push ahead on HIGH SIDE another five feet. Again, if you can see you are building too much angle, withdraw to your previous position and once again begin rotation. Rotate ahead ten feet and stop. Check that you have a straight push and continue working the motor or jet into the ground very carefully. Always be high when you spud and work yourself down to the correct position. Remember, it is easy to drop angle in surface soil. It is impossible to build angle once youve already dropped! Continue working the motor into the ground until the non-mag collar is in the vices. Take a Print Screen. Note the position on the printout. Add the final length of the down-hole assembly. Push this to the vises using a combination of high side and rotation. At this point, reenter the Set Up Survey File and correct the Tie-In information if the actual entry point is different than your planned entry point previously input. Take the first survey using the first course length you calculated and observed earlier. Note all data on the Tabulation Sheet. Carefully study the data as a reasonable test. Does the calculated position look correct in relation to what you observed. If not, look for your mistake and correct it before continuing to drill. Make sure NOW, that everything is correct and ready to drill.
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You have completed a successful straight spud. 10.8 Drilling Ahead There are a number of functions you are required to fulfill during drilling operations. Not only will you be ensuring proper tool operations but you will always be concerned with the position of the bore.
10.8.1 Tool Operation
Throughout the job, you are responsible for the proper operation of the tool. You not only need to constantly look for problems, but also ensure good data quality. Keep all required records up to date! Completely fill out the Tabulation sheet, and your daily reports as things progress. Ensure that you observe the tool operation constantly looking for shorts in the wireline. Be available to the driller to answer his questions regarding magnetics and what is / is not possible. Keep your mind on the job of ensuring good equipment operation. Be the first to spot something going wrong either with our equipment or theirs! Assist the driller in looking out for the safety of the rig crew. Four eyes are better than two! When you are concerned about equipment operation, make the driller aware of your concern and have him shut down until the problem can be explained. A problem spotted early can be fixed immediately rather than wasting time later in the job when down time is more risky.
10.8.2 Data Quality
In addition to proper tool operation, you are responsible for the accuracy of the bore path with or without interference! Since our performance is measured by where the bore exits in relation to the target and the distance you may be off centerline during drilling, the data quality is critical you that performance. You must make every effort to ensure you have justifiable reasons for any decision you make in relation to the data quality. You must construct a Mag / Dip Chart (see Section 5.7.1.4) when you have interference! You must ensure that switch off and switch on readings are the same. If not, find out why. In some cases, you may take a survey before the probe has settled to a final number. You Switch off after the survey give the go ahead for the driller to make a connection. After the connection, you Switch On and find the inclination is now half a degree lower. Immediately, delete the survey you took and retake it all while still at the top of the next joint. Then correct your paperwork and begin drilling. While drilling with a motor, the readings will be bouncing around as the G - Totals lower. Be available to assist the driller in determining what is the correct number.
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10.8.3 Projections
Always be available to project ahead mathematically from your current position. You need to do this based upon the response your drilling assembly is giving you during the build sections of the bore. If for example you are not achieving your expected radius, you must calculate exactly how much deeper than plan you expect to be. This fact must be brought to the attention of the customer to gain his approval. In this example, you will not only be lower than plan but you will need to replan the exit curve taking into account the larger radius you are achieving. This will completely change the entire profile, in some cases to an impossible situation. The earlier you know this the sooner you can correct the situation with a trip to change assemblies. The earlier you involve the customer with the problems, the easier it will be to gain his approval in whatever action you recommend. Always, project ahead to satisfy yourself everything is being done to meet your objectives. 10.9 Directional Control Decisions Always know where you are in relation to the plan. Always know where you are in relation to the surrounding topo. Always know where you are in relation to subsurface obstructions.
10.9.1 Radius Control
You should know where your course is in relation to the planned radius. In order to do this you must plot radius targets on the vertical profile. The fastest and easiest procedure to follow is as follows. SIN 1 Degree Times Planned Radius = Measured Distance along Curve Take the resulting distance and using an engineers scale, begin scaling the distance from the beginning of the curve. Place a tic mark at each scaled distance. For example, if the planned radius is 2000 and the entry angle is 12 Degrees, the Sin of One Degree Times 2000 equals 34.9 Feet. Measuring this distance from the beginning of the curve, place a tic mark 34.9 feet along the curve. From that point, place another tic mark 34.9 further along the curve. Continue placing the tic marks and scaling until you reach the end of the curve. This should measure exactly that point where the planned curve reaches 90 degrees. If it does not, check for errors. Once the tic marks are plotted, write in about an inch above the tic mark the projected inclination planned at that point. Again, if you started at 12 degrees ( 78 Degrees from Vertical), you will have ascending numbers, ie. 78, 79, 80, 81 ... 90.
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Your plan is now in place. While drilling the curve, plot your position as normal. Look at the inclination and compare it to the planned inclination at that point. If your actual inclination is lower than plan, you will reach the bottom of the curve lower than planned, if you respect the radius limit. At this point you will need to discuss radius limits with the customer pointing out your position on the plot and what you will need to do to bring the curve back on line. Do not make this decision yourself. If your inclination is higher than plan, at any point, you will reach the bottom of the plan, higher than planned. You may relax the radius slightly. Do not do this over two or three joints. Project ahead a smaller radius to reach 90 Degrees at the same point as the original plan. Always compare the plotted positions inclination to planned inclination at the same away distance. This is the only way you will obtain early warning of future location problems.
10.9.2 Intermediate Targets
Every joint you drill should be towards an intermediate target. Setting targets is a function of present inclination and azimuth, planned inclination and azimuth vs present and planned positions. From the radius tics you will know if you are ahead or behind the curve. If you are on the curve and do not need to break or relax the radius, the projected inclination target is easy. Next Joint Length Divided By (Sin 1 Degree X Radius) = Expected Degrees per Joint Add the quantity derived to the previous inclination to generate the next intermediate target. If the centerline is straight, the target azimuth should be the same. If you are right or left of the line, you should normally attempt to close the line slightly by giving the driller a target pointing towards the line. Normally a 5 Degree left or right toolface setting on one joint, both high and low side will achieve an azimuth movement of between 0.1 and 0.3 Degrees. A 10 Degree toolface set, will achieve 0.2 to 0.5 degrees of azimuth.
10.9.3 Radius Calculations
Never turn the bore without a plan taking radius into account. In the example above of a 2000 foot radius, if you achieve the exact planned radius on inclination and one half degree of turn in a joint, you will have exceeded or broken the radius by a factor of around 10%. Very roughly, you may use a rule of thumb to calculate a combined radius as follows. If you add the change in inclination and the change in azimuth in degrees, and take 70% of the result, you will roughly approximate the angle on a combined basis. Then determine the radius of the change in combined angle.
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30 Joint Divided By ( SIN 1 X Angle ) = Resulting Radius Example 1 2000 Radius Planned = 0.86 per 30 Joint Previous Inclination Previous Azimuth Present Inclination Present Azimuth 81.5 -80.5 1.0 80.5 271 81.5 271.5 271.5 -271.0 0.5
(1.0 + 0.5)(.7) = 1.05 30 Divided By ( SIN 1 X 1.05 ) = 1637 Radius Example 2 2000 Radius Planned = 0.86 per 30 Joint Previous Inclination Previous Azimuth Present Inclination Present Azimuth 81.4 -80.5 0.8 80.5 271 81.3 271.5 271.5 -271.0 0.5
(0.8 + 0.5)(.7) = 0.91 30 Divided By ( SIN 1 X 0.91) = 1889 Radius Example 3 2000 Radius Planned = 0.86 per 30 Joint Previous Inclination 80.5 Previous Azimuth 271
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Present Inclination Present Azimuth 81.0 -80.5 0.5
81.0 271.5 271.5 -271.0 0.5
0.5 + 0.5 Times 70% = 0.70 30 Divided By ( SIN 1 X 0.70 ) = 2455 Radius You can see from these examples how sensitive the radius actually is to combined changes. In determining an intermediate target, you must ensure that you respect the radius on a vertical and a combined basis. If you exceed the radius, you must have the customers permission to do so. The survey printout at the end of the job will form the basis of proof.
10.9.4 Radius Averaging
It is not realistic to attempt to drill a perfect radius. In the real world, no amount of calculation will achieve a perfect radius on every joint. The formation will push you up, down, left and right as you drill making the attempt of a perfect bore difficult if not impossible to achieve. You must control the radius rather than letting it control you. This means making early decisions, ensuring good communications with the customer and averaging. The expression of Dog-Leg on the MGS screen is an angular expression of radius. Using the formula above in 10.9.3, ie.: 30 Joint Divided By ( Sin 1 X Dog Leg Angle Degrees ) = Radius After surveying a joint, look at the Dog Leg Angle. Change it to radius by using the above formula. If the result is acceptable, note it on your Tabulation sheet. Continue making notes on every joint. Since Dog Leg is an expression of a combined radius as an angle, and it is projected out over 100 feet, it is quite correct to average three 30 joints to better approximate the real radius. A point 30 from the previous which results in an1600 Radius when the target radius is 2000, may be accepted IF the following two joints average 2200. The sum of the three joints will total 6000 which when averaged will result in an average radius of 2000. Use a running average throughout the curve. Remember, when using Dog Leg, this is a combined curve angle. The probe resolves azimuth from the earths magnetic field. Therefore, if there is magnetic interference, the dog leg angle will be incorrect. You must correct the Azimuth FIRST, by plugging the Azimuth
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when you take a survey, or by editing the survey file and recalculating before you will be able to use the dog leg in radius terms.
10.10 Directions to Driller
There are three types of driller. You will find those who want you to give then angular targets, position targets and those who need your assistance to hit a target.
10.10.1 Angular Targets
This target is one where you ask the driller to build or hold inclination to a particular number, ie. 86.5 Degrees. Azimuth of 217.5 Degrees. You will have calculated these numbers already and have them available when required.
10.10.2 Position Targets
This target is subjective. Build 2 Degrees and go straight ahead, for instance.
10.10.3 Target Assistance
This is Tool Face setting. Normally, you will need to provide this type of assistance to drillers in training. You will need to watch him drill the joint and tell him exactly what you want him to do while drilling. High Side for 10. Rotate for 5. Stop and lets look at the result. Another example would be : 15 Degrees Right for 8 and rotate for 7. Stop and lets look at the result. Rotate the joint down and come to high side.
10.11 Communication
It can not be stated enough. COMMUNICATION SKILLS are necessary for a job to progress smoothly and for you to be asked to return on the next job. If you do not communicate with every person on the crew, you are doing them a disservice as well as us. You must communicate with the customer. Throughout this manual, you will find points where it is necessary to communicate. Every point is mandatory. You need information at the beginning while the customer needs information during the job. You both can only obtain this information through communication. If the customer does not understand your job, he will not want to understand your problems if you have not attempted to involve him in your decision making. Many times, he will have practical solutions you have not dreamed of to a problem. Do not surprise a customer. Always advise him of the progress and what you are doing to ensure a good steady course.
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10.12 Drilling Problems You are normally on location to guide a bore to a predetermined target. Many times you will have more drilling knowledge than the customer. DO NOT make him uncomfortably aware of this. If you are being paid for guidance, stick to guidance.
10.12.1 Customer Assistance
If you are asked for assistance in solving a problem within your expertise, let the customer know what you advise and why. Let him make the decision. Out of the four Engineer levels within Sharewell, there are only two levels qualified to render drilling assistance. If you are not in that bracket, then stick to guidance. Do not get yourself into a mode of advising customers what other customers do in these situations. This is a disservice to those other customers who in some cases spent years learning the correct drilling solution to a particular problem. Until you thoroughly understand the mechanics behind a drilling solution, do not pass on other peoples solutions. You will be seen through very quickly.
10.12.2 Wireline Shorts
In dealing with any wireline, you will experience electrical shorts. You need to understand how to troubleshoot shorts to determine their location. The short is exemplified when the amp needle on the front of the Interface moves to maximum and or the power fuse blows. The most likely place for a short is downhole at a wireline connection or at the centralizer blades on top of the probe.. You should begin looking downhole. Rig a test lead from the positive terminal of the interface box long enough to reach the wireline from the pipe in the rig vises. Remove the existing power lead from the interface and connect the test lead. Switch on the probe and determine proper operation. If the test indicates a short is present, the short is down hole. Trip pipe back until the short is located. If the probe works normally, the short in somewhere between the interface box and the wire connection on the rig carriage. Continue isolating discrete strings of wire and testing either with the probe or with a continuity tester until you locate the short. In some cases, the short will be intermittent. These are the most difficult to locate. You must continue moving the wire, up hole or downhole until the location is found. Many times a quick test with a VOM meter of the probe, will give you an idea if the short or leak is downhole.
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First, disconnect the test lead from the wireline of the joint in the vises. Using a VOM meter set on resistance scale to at least 300 OHMS, and connect the leads between the power wire and ground. Use the joint for ground. You should read a resistance of between 20K and 40K OHMS. If you read more than 40K, a wireline leak exists between the test lead and the probe. It is advisable to pull on the wireline at times during the test to attempt to make the readings vary indicating a leak. Reverse the test leads. Watching the meter, you should see a Capacitance kick. The needle should kick to about 300 OHMS and gently bleed back near zero.
10.12.3 Wireline Leaks
A Leak, is still defined as a short, but Probe operation continues. The leak is not yet large enough ( 200Ma ) to stop probe operation. Leaks will generally turn into shorts with time. In some cases, they will cause a trip within a couple of joints, and in other cases, you may drill the entire crossing with the leak. A leak is caused normally by wire insulation damage. The wireline may be skinned, exposing the wire to the mud. Power will be lost to the mud in varying amounts until the leak becomes too great and the fuse blows. A leak may heal itself on occasion. The electrolysis effect of copper and the mud can cause oxidation of the copper wire, effectively building a non-conductive coating around the wire. This then seals the mud away from the current, reducing the quantity of amperage being lost. This will happen only with very small leaks where the insulation may only be slightly cut. This insulation effect will be lost completely if ever you elect, for other reasons to change over the mud system from mud to water. The water will wash the coating away, once again leaving copper exposed to the fluid. Downhole leaks should be treated as shorts, identified and a course of action determined. It is normally wise to go ahead and trip to locate and repair the leak early, rather than attempt to live with it for a whole job. On the other hand, if you are 2-300 from punch out, the customer may wish to go ahead and attempt to make the distance. This should always be his decision. He is depending on you to make a judgment of success.
10.12.4 Wireline Opens
A wireline open, is defined as zero continuity between the interface and the probe. The Amp needle on the interface will not move. This indicates a wireline break somewhere in the system. The positive or negative wire may be broken. If the wire breaks downhole, normally, you will see some amperage on the needle. Begin looking for an open, on surface between the interface and the rig connections.
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10.12.5 Tripping Pipe OUT
You must keep track of exactly how many joints of pipe are below the vises at all times. All your measurements are made from this reference point which makes this of real importance. When drilling problems force a decision to trip out, either a few joints or all the way, you must keep track. Since you normally have started drilling a new joint which has not been surveyed, you should lay down that first joint and note its unsurveyed depth and number on the Field Tabulation Sheet. Each further joint you lay down on the rack, indicate on the left side of the Tab sheet, an arrow pointing up, next to the joint number. Continue removing joints and noting the arrows until you reach the planned number. Once youve removed the required number GO OUTSIDE and count the joints you have removed. Compare the number to your noted numbers for agreement. If they do not agree, count all joints on location, add the downhole joints and compare the total joints to the total joints on location you counted at the beginning of the job. Be precise and make sure you can account for every joint.
10.12.6 Tripping Pipe IN
On your return in hole, place an arrow, pointing down, against each arrow you previously noted coming out once each joint is down. Using a test lead, power up the probe about every five joints and take a print screen. Nota the inclination and azimuth on the Tabulation Sheet against the representative data. Compare constantly. The readings should be similar. 10.13 Punch Out Well prior to punch out, you will have been determining your margin for error in elevation. Given good TruTrack readings, you will know where you are in elevation within a small tolerance. If you are on a long job, the elevation accuracy may degrade due to a number of factors. Driller Bias, distance errors, formation tendencies, short TruTrack coils, no TruTrack coils and survey calculation methods are a few examples. You should recalculate your complete survey against both Average Angle and Tangential methods a number of times during the job to compare the methods. Normally, one method will match TruTrack better than the other. In most cases, the methods will produce a bracket of elevation numbers. Tangential may show you at -22.5 while an Average Angle calculation shows you at -26.0. At the same point, TruTracker will normally be in between the two, say at 23.5. This will normally indicate the actual elevation to be between the Tangential and TruTrack readings. Plot each elevation as points throughout the last 200. Discuss the different calculation methods and error possibilities with the customer and determine his wishes as to crossing length.
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He may prefer you to be short rather than long. He may indicate that he only has the required length of product pipe as planned. This would mean that you can not be long. The best case naturally is that all methods are close. Do not count on it! Play the percentages and plan ahead. Remember, when you punch out long, failing a major pull back and sidetrack, you will not be able to redrill to a shorter location. Punching out short gives you the option of pulling back a couple of joints and lengthening the distance considerably 10.14 Construction of As-Built You should as soon as feasible, construct your as-built print out. Physically measure the punch out position and note it on your Tabulation Sheet as well as your daily report. Take an initial print of the survey using the Survey Processing and Printing Screen in the Program. Compare the final position on paper to the actual punch out position. Use whichever calculation method best approximates the actual punch out elevation. Determine the calculated left/right position and compare it to the actual punch out location. If you have been steering to punch out using TruTrack readings and not azimuth there will be a difference. Determine the closure angle between the two positions as follows: Divide the difference between the actual and calculated left/right positions by the horizontal length of the crossing. Take the Arc SIN of the result. This is the overall angular difference from the beginning of the crossing which when applied to the line azimuth will overlay the actual exit point and the calculated exit point. If you have plugged azimuths based upon justifiable analysis, compare the course with TruTrack positions to find the best fit. You may find that the best fit causes you to change the values of the previously plugged azimuths. Make up clean copies of the as built and leave the customer with a copy. Place a copy in the job file.
10.15 Rig Down
The pilot hole is over. You hit the target and everyone is happy. The rig crew wants to get the rest of the job done so you are now extra to requirements. You need to pack up your equipment and depart.
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First, go to the exit side and supervise the removal of the probe from the down hole assembly. This is important. Most probe damage happens on surface during rig up, rig down or travel. Once you have the probe, return to the entry side and pack up the surface equipment. Once packed, ensure the customer has copies of all necessary job paperwork. Complete the job ticket and have it signed by the customer. Visit each individual on the crew and personally say goodbye.
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11.0
Hole Opening
Final product installation will often require the pilot hole to be enlarged. This phase of the project is called hole opening or reaming. The overall costs of hole opening varies from project to project. In alluvial soils, conducive to maintaining a firm wall and trouble free pull back, hole opening can proceed with speed. In rock formations, hole opening takes on added significance and can become a high percentage of a projects overall cost. Time and the cost of equipment are not the only considerations when budgeting a rock crossing. The risk factor increases in relation to the diameter of the bore. This aspect of horizontal directional drilling should be calculated and considered. The hole opening phase of a rock crossing must be well planned and as coordinated as the pilot hole portion of the project. Planning naturally does not guarantee success. However the consequences of poor planning is costly and can become financially disastrous. When designing a rock crossing do not underestimate the importance of a complete, well thought out, drilling prognosis. 11.1 Alluvial Formations Alluvial formations may be generally defined as jettable. These include sands and clays, that allow a jetting type assembly t be used and steered from entry to exit. Normally, the formation strength should be around 800 PSI of less depending on crossing length.
11.1.1 Reaming Alluvial Formations
The product line will often require the pilot hole to be enlarged to a diameter sufficient to allow unrestricted pullback. In alluvial formations this is accomplished by rotating and in most cases, pulling a fixed tooth type reamer back through the pilot hole. These type reamers are often called Fly Cutters.
11.1.2 Fly Cutters
As is the case with jetting assemblies, fly cutters have many styles. Most are very similar in their basic design. Spokes, usually three, are welded to a mandrel with threaded connections machined on each end. A ring is attached at the outer edge of the spokes giving the assembly a wagon wheel appearance. Numerous carbide teeth are held in place by Blocks, which are welded up and down the leading edge of the spokes and the outer ring. These teeth are tilted toward the direction of rotation. The angle of this tilt is based on the operators experience, personal preference and is some cases, calculation.
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The spokes of the fly cutter are hollow, allowing fluid to be pumped through the drill string, into the spokes and out the nozzles to the bore hole. This jetting action removes loose formation and increases penetration rates. Fly Cutters may be built to any nominal size When the pilot hole has been completed and the jetting assembly removed, the fly cutter is made up into the drill string on the exit side with the cutting face towards the rig. The hole enlarging is usually done by pulling back to the rig. rather than pushing from the rig. The enlargement size is determined by the pilot hole diameter, the formation and the rig capabilities. A 9 7/8 pilot hole can, in some cases, be opened directly to 36 or more, depending on the formation. Most of the time it will be opened incrementally, ie. to 24 and then to 36. for example. The back reaming or opening begins by turning the pumps on and beginning a slow rotation. A block sub will be placed behind the fly cutter forcing the mud flow through the fly cutter nozzles. The assembly is then rotated and pulled back through the formation, enlarging the pilot bore and flowing the cuttings out of the bore. Due to the volume of formation to be removed, great care should be taken to determine the best rate of penetration for formation removal. It is very easy to make faster progress with the tool than the mud velocitys ability to remove the same amount of formation. In this case you will leave most of the formation in the borehole and do nothing more than create an extremely heavy slurry in the bore. This will cause problems during product line installation. The RPM and Pull are increased until optimum penetration rates are achieved. Rotation should remain constant to avoid uneven torque in the string. After the hole is opened to the desired diameter, the product line can be pulled. The installation of the product line and back reaming, in some cases, may be accomplished on the same pass. This requires a Swivel to be made up behind the fly cutter. The swivel will allow rotation of the fly cutter and drill string but not the product line.
11.1.3 Barrel Reamers
Barrel Reamers are similar to Fly Cutters in that fixed carbide teeth are attached to the leading edge of the reamer with nozzles to allow a pilot hole to be enlarged. Barrel Reamers can also be constructed to any required size. The barrel reamer is constructed much like a fly cutter except that the mandrel is centered within a section of casing. This is done with gussets, welded to the mandrel and to the inner wall of the casing. End Caps are then placed on each end of the casing. The barrel like appearance is the obvious source of its name.
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There are many designs of the barrel reamer. Some have a more pointed cap at each end. These are sometimes called Bullet type reamers. Some are ported to allow the entire cylinder to fill with drilling mud while others have compartments to allow partial filling only. This allows us to calculate a neutral buoyancy for each tool. The jetting action is accomplished with nozzles placed on the leading edge and sometimes at each end of the reamer. These type reamers are often pulled ahead of the product line during installation. For example, a 28 reamer could be pulled ahead of a 24 line into a previously reamed 30 bore. The purpose of the barrel reamer is to compact the formation left in the bore from previous passed and allow a smooth pullback of the product line. The cutting structure would break up obstructions left in the hole. Barrel reamers are good choices for packing and stabilizing the bore walls in soft unconsolidated formations.
11.1.4 Hydraulics
Using Fly Cutters and Barrels is alluvial formations require a good hole cleaning plan, in most cases, a better plan than drilling rock. Since the large diameters of fly cutters generate a very low annular velocity of mud returns, much of the formation stays in slurry in the bore hole. This will compact to the wall when pulling a barrel in front of the product line. If too much formation has been left behind, product line sticking may be the result. Study the Formation Volume Tables and make up a hydraulics plan to allow removal of a specified formation volume. 11.2 Rock Formations When it is determined the bore will or could encounter rock additional preparation is required. Rock will affect a project in a variety of ways. *The risk factor is increased. *Additional equipment will be needed. *Penetration rates will decrease increasing the time needed to complete the project. Rock is not necessarily a negative. Some rocks drill extremely well and are easier to open to the desired diameter than unconsolidated alluvial formations. There are many types of rock each of which has unique characteristics. Each will drill differently and require equipment designed specifically for those characteristics. Choosing the correct equipment is essential to optimum penetration rates and tool life. To choose the correct equipment the characteristics and properties of the rock must be known. The following chart illustrates the Compressive strengths (PSI) and Mohs hardness of specific rock.
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Description
Rock Formation
Compressive Strength (PSI)
Mohs Hardness
Soft
Talc Shale Clay Mudstone Gypsum
0-6,000
1 less than 3 1.5 - 2.8 1.5 - 2.8 2
Medium
Calcite Limestone Marble Slate Fluorite Apatite Sandstone Dolomite Graywacke Feldspar Granite Schist Gneiss Quartz Quartzite Diorite Basalt Taconite Dyke Topaz Corundum Lava
6,000 - 12,000
3 2.2 - 3.3 2.4 - 3.2 4-5 4 5 3-6 5.2 - 6.7 5.6 - 6.8 6 6-7 6-7 6-7 7 6-7 7 - 7.5 6.8 - 7.8 7 - 7.8 8 8 9 9
Medium Hard
12,000 - 25,000
Hard
25,000 - 45,000
Very Hard
More than 45,000
11.2.1 Tool Selection
During the planning phase of the project, you will have determined the tool selection and already have equipment on location. Unless you have learned from drilling the pilot hole that you need to make a change to the plan, stay with the plan. Otherwise, Prior to finish of the pilot hole, make another plan and ensure the correct equipment is available when you need it. Final rig up of the assemblies can now begin with a proper hydraulics program focused on optimum hole cleaning.
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11.2.2 Jet Nozzle Sizing
The pressure drop across the nozzle results in the jetting action needed to remove formation from the cutters and clean the shoulder of the enlarged hole. The efficiency of this cleaning is obtained by keeping the pressure at the nozzles as high as possible while maintaining the minimum annular velocity required. Nozzles too small will not allow the volume needed to carry the formation out of the hole. Nozzles too large will lower the jetting action, fluid turbulence and impact the cleaning ability of the cutter. Pressure drops across the nozzle can be calculated using the following formula: G = Gallons per minute D = Mud weight per gallon A = Nozzle area or total flow area C = Orifice coefficient (.95 for a bit orifice) Pressure Drop = G2 X D 12031 x A2 x C2
Pressure drop creates Jet Velocity - Jet Velocity is measured in feet per second. The jet velocity has minimal effect on penetration rates while hole opening since the jets are positioned too far from the formation to receive much benefit. Proper jetting requires a hole opener to be set up such that a minimal pressure drop of 300 psi is maintained.
11.2.3 RPM and Weight
Penetration rates during the hole opening process will certainly be determined by the formation being opened. Guidelines can be given but the appropriate weight will be determined as the hole enlarging progresses. Variables are the type of cutter being used, the diameter of the tool and the formation. Torque should be kept within the parameters of the drill string. Generally in soft formations, penetration rates respond to higher speed and lighter weight. Hard formations, lower speed, and higher weight. RPM should be kept as slow as practical to prolong cutter life. Because of the positioning on the outer periphery cutters on larger diameter hole enlargers will rotate faster than those on smaller diameter tools at the same rotary speed. 17-1/2 hole enlarger has 9-1/4 cutters as does one style of 36 hole enlarger. At a rotary speed of 75, the cutters on the 17-1/2 tool will rotate on their axis at 142 RPM. The same cutters on the 36 tool would rotate at 292 RPM at the same rotary speed.
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Recommended weights vary with cutter type and tool diameter.
Maximum Recommended Weight, Lbs./Inch Hole Enlarger Diameter
Type Cutter Soft Mill Tooth Hard Mill Tooth Chisel Button Conical Button
Weight 1000# 1500# 1200# 1400#
The above maximum weights are based on a minimum pilot hole required. When enlarging a larger pilot hole, reduce the weight on a directly proportional basis. A 36 hole opener following a 17-1/2 pilot hole, using chisel button cutters should operate under the following guidelines: 43,200# on tool and an RPM of about 42. The same tool opening a 26 pilot hole should follow guidelines of: 23,400# on tool and an RPM of about 42. If broken formations are being encountered and rough drilling conditions exist, adjust weights and RPM to avoid bouncing. Good stabilization will reduce effects of rough formations. Remember, penetration rates will decrease as the amount of formation being removed increases. Often, even in hard formations, better performance may be obtained using less weight. Do not unnecessarily try and muscle your way through. Patience and proper RPM/Weight for the tool and formation will extend the life of the hole opener saving time and money in the long run.
11.2.4 Centralization
While a number of factors affect hole enlarger performance, none are as vital as centralization. Centralization gives the hole enlarger the ability to perform in the geometrical parameters of its design. Important under any circumstances, Horizontal Directional Drilling dictates increased attention be given to centralization.
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Gravity, an asset in stabilizing vertical drill strings, becomes an adversary in horizontal drilling. The life expectancy of downhole tools is shortened in a horizontal hole. Even the drill pipe suffers a degree of wear not seen in vertical wells. The more abrasive the formations, the shorter the life expectancy of tools and drill strings. As the diameter of the crossing increases so will the torque needed at the hole enlarger. The longer the crossing, the greater the friction on the drill pipe. This drag uses needed rotary torque. Whipping or bowing of drill pipe causes a magnified wobble effect at the tool. The cutters are unable to maintain constant contact with the shoulder and cutting efficiency is lost. Not only are the cutters subject to jarring and banging, the entire string is exposed to uneven torque and spin forces. Tool joints are damaged and the possibility of parted drill pipe is incurred. The hole enlarger, if properly stabilized, will rotate on its axis maintaining contact with the cutting shoulder. This allows the cutters to rotate and cut as they were designed. Stress on the tool and drill string are reduced allowing maximum torque exchange from the rotary to the hole enlarger. Centralization can be achieved with welded blade stabilizers or blade type roller reamers. Welded blade tools will tend to try and ream on the low-side of the hole. If a shoulder is built by rotating in place, wear will begin at the front of the tool. Eventually the blade O.D. will be reduced by several inches. Even before the blade is worn, the centerline of the assembly is lowered due to the shoulder being reamed. This caused the shoulder the hole enlarger is cutting to become narrow at the top and thicker at the bottom. This hinders the efficiency of the hole enlarger. It is important to request centralizers with full wrap rings or spiral blade stabilizers with a complete 360 wrap. This will eliminate flats on straight bladed or partially spiraled stabilizers allowing smoother rotations. This decreases the reaming tendencies of the stabilizers and reduces torque. In consistent rock, roller reamers will provide superior stabilization to blade type stabilizers. They will resist wear thereby maintaining proper gauge. The rollers will reduce torque in the string allowing more accurate reading of the torque at the hole enlarger. Optimum placement of centralizers in the downhole assembly is the same for welded blade tools or roller reamers. Place a centralizer directly in front and behind the hole opener with another placed one joint behind the hole enlarger. The pilot centralizer should be gauged slightly smaller than the diameter of the pilot hole. The centralizer behind the hole enlarger should have an outside diameter
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slightly less than that of the hole enlarger. In a well cleaned hole, reduced wear will result in extended hole opener life.
11.2.5 Hydraulics - Hole Cleaning
The ability to lift particles and cuttings out of the hole is the most important function of drilling fluid. Annular velocity ( AV ) is the key element for keeping the hole clean. Annular velocity is the velocity of fluid movement in the annulas created between the O.D. of the drill pipe and the diameter of the hole being opened. The formula to calculate annular velocity is: Annular Velocity (FPM) = Flow Rate (D - d2) .0408
2
Flow Rate = Mud flow rate in gallons per minute D = Diameter of enlarged hole in inches d = Diameter of drill pipe in inches Because the formula is based on a closed system it cannot be used after completion of the pilot hole. Hole cleaning during the enlarging process is difficult to achieve and to monitor. A 12-1/4 hole will generate about 130 pounds of earth materials for every foot of hole that is drilled. When hole opening, an enormous amount of drilled cuttings are entering the mud system. It is possible for penetration rates to exceed cleaning capabilities. Saturated drilling fluids will pack off and cause a stuck string. This can be avoided by not exceeding your planned ROP for optimum hole cleaning. As the hole diameter increase the annular velocity decreases. Drilling mud should be adjusted to increase its lifting and suspension properties. Returns coming over the shaker should be monitored closely. Expect large amounts of formation. If good penetration is being experienced and solids coming off the shaker are decreasing a problem in the hole has occurred. It may be necessary to trip out of the hole to break-up and dislodge obstructions in the bore. As the hole diameter increases, sections of the bore can slow or breakoff into the hole. Gravel, cobble and even boulders can become dislodged as the support around them is removed by the hole opener and circulation of drilling fluids. These obstructions will not be lifted, and carried out of the bore by the drilling fluid. Some will be drug and pushed out of the hole by the downhole assembly. Most will remain at the lower portion of the bore.
122
Section 11:
Hole Opening
Their numbers can be minimized by minimizing the number of trips through the sections generating the cobble or rock. It may also be possible to case the hole down through the problem section. Hole cleaning during hole opening will rely on a steady flow of mud being passed out of the bore at a rate capable of removing the amount of formation being out. Do not let your penetration rate exceed the ability to clean the hole. In cases of drilling with lost circulated pay special attention to abrupt changes in penetration rates, pump pressure fluctuations, increases in rotary torque on and off bottom and changes in drill string drag.
11.2.6 Changing Cutter Assemblies
To remove cutters from a 17-1/2 hole opener: 1.Drive the lock pin out using a hammer and punch. 2.Screw puller assembly into cutter pin. 3.Pull pin with sharp thrust of the sliding knocker. 4.Remove cutter from cutter pocket. To install new cutters on a 17-1/2 hole opener: 1.Seat cutters in pocket aligning the cutter pin hole. 2.Slide cutter pin through hole opener arm and cutter. 3.Align lock pin hole with groove in cutter pin. 4.Drive lock pin in place. To remove cutters from 26 and larger tools: 1.With 1/2 allen wrench remove lock screw. 2.Screw puller assembly into cutter pin. 3.Pull pin with sharp thrust of the sliding knocker. 4.Remove cutter from cutter saddle. To install new cutters on 26 and larger tools: 1.Seat cutter in saddle aligning the cutter pin hole. 2.Slide cutter pin through saddle and cutter. 3.Align saddle screw hole with cutter screw hole. 4.Tighten lock screw until threads bottom out. Tape wrench with hammer until not movement is felt.
123
Section 12:
Motor Operations
12.0 Down Hole Motor Operations

The purpose of this manual is to acquaint personnel with the construction, operations, operating parameters, and simplified trouble shooting of the Black Max positive displacement motor (PDM). This manual is not designed to replace the motor supervisors common sense experience or to be the gospel in proper use of the PDM. The manual is designed to assist in efficient proper motor operations as well as to offer trouble shooting tips. 12.1 Drilling Fluid Requirements To achieve maximum performance, a positive displacement motor is designed to accommodate an exact flow of fluid normally quoted in gallons per minute. The fluid volume required to develop optimum horsepower for each tool size, tool dimension, and recommended operating condition will be found in the motors spec. sheets. Drilling fluid enters the motor between the spiral rotor and stator and continues through the tool between the connecting rod and housing. The PDM operates effectively with practically all types of drilling fluids ranging from water to very heavy drilling muds including oil base muds, salt water muds, oil emulsion muds, clay base muds, and high viscosity muds. Also muds with practically all types of lost circulation materials in concentrations to 9 or more lbs/bbl. have been used successfully. A PDM will also operate with high pressure air or gas. Fluid weight or viscosity has little effect on the tools performance. Mud weight has a direct effect, however, on the total pump pressure requirements. The PDMs performance is more closely related to the amount of drilling fluid used than to the type of fluid. For maximum performance, the volume in gallons per minute of fluid for each tool is of utmost importance. Caution: Free solids in drilling fluids, i.e., sand can affect tool performance by accelerating motor element wear. Sand content should be held to an absolute minimum, less than 1%.
12.2 Fluid Pressure Requirements As fluid is pumped through the PDM and the tool is running free off bottom, the pressure across the tool is constant, ranging between 50 psi and 100 psi for the different sizes of tool. As the bit touches bottom and bit weight is added, the fluid flow pressure increases. This increase in pressure is directly proportional to the additional bit weight or the drilling torque required and is called the pressure loss or pressure drop across the tool.
124
Section 12:
Motor Operations
As more weight is added, the gage pressure will increase until the maximum pressure increase is reached. At this point, the maximum torque is produced, and the motor stalls. This is indicated immediately by a pressure increase of several hundred pounds psi on the mud pressure gage. As weight is added or deleted, it will normally increase or decrease gage pressure accordingly. The maximum or stall pressure can be spotted when the mud pressure gage suddenly jumps several hundred psi and does not vary as additional weight is added to the bit. When this occurs, the seal between the rotor and rubber stator is broken, and the drilling fluid flows through the motor without rotating the bit. For optimum performance and tool longevity, the pressure loss across the tool should be restricted to concur with the data published for each tool size and type. Caution: Excessive bit weight should be removed as quickly as possible, since major motor damage will occur if fluid is continuously pumped through a non-rotating motor. 12.3 Torque Being a positive displacement tool, the PDM offers a unique feature ... the drilling torque is directly proportional to the pressure increase of the fluid flowing through the tool. In addition, the speed of the tools hydraulic motor is directly proportional to the fluid volume. 12.4 Tool Life The life of a tool is determined by the environment in which it operates. The following conditions will tend to shorten tool life. a) b) c) d) e) Abrasive muds. High temperatures. Drilling with excessive pressures. Excessive back pressure on the bit. Excessive pressure drop across the motor. Bit weight should be adjusted so that the pressure drop is witnessed on the pressure gage. By following recommended procedures optimum drilling performance and tool life are achieved. Hard or abrasive formations. Pumping excessive fluid. Excessive loading.
f) g) h)
12.5 Starting the Motor on Bottom Upon reaching the desired off-bottom depth, the pumps can be started. The pressure increase should not, however, exceed the calculated off-bottom pressure. The surface pump must be set to the exact desired strokes to provide the proper gallons per minute flow for the size of tool being operated.
125
Section 12:
Motor Operations
The hole should be adequately cleaned before starting orientation as a dirty hole can affect the torque. 12.6 Pressure Drop and Torque When the hole is clean and off-bottom pressure established, the tool gently to the bottom. Continue to add weight until the additional recommended differential pressure shows on the pressure gage. This will determine the optimum drilling weight for continued operation. By maintaining this pressure constantly, the torque should remain the same through the run. Adding weight will increase the pressure and the torque. Reducing the weight creates a reduction in both pressure and torque. As a result, the rig pressure gage enables operators to tell at a glance how the tool is performing and will serve as a drilling weight indicator.
12.8 Planning Procedure The selection of the proper tool and accessories should take into consideration the following items: 1) 2) 3) 4) 5) 6) Hole size. Bit size. Angle of hole at the beginning of the job. Availability of sufficient hydraulic horsepower at the rig to meet recommended standards in gallons per minute and pressure drop. Working plan for achieving directional target, i.e., build - turn - drop, etc. Accessories: a) Proper angle bent housing. b) Drill collar assembly.
12.9 The 6-3/4 Slo-Speed PDM

12.9.1 Parameters
Hole Size:
8-1/2 to 9-7/8 - in some extreme cases 7-7/8 holes or 10-1/2 holes Tri-cone sealed bearing rock bits, polycrystalline crystalline diamond bits (PDC), Thermally stable diamond bits (TSD), or natural diamond bits. Liquid: Air: 300 GPM to 600 GPM 1350 cu. ft./min. to 2700 cu. ft./min. with 7-10 lbs. of water-soap mixture being misted into the air stream.
126
Bit Types:
Fluid Flow:
Section 12:
Motor Operations
The PDM does not worry about the pressure of the stream. Proper flow rates determine the efficiency of the power and drill bit speed. In river crossings experience has shown that many bores may be drilled using less than the recommended minimum. Experimentation on each job will help determine the optimum fluid flow rate. In soft soils lower flow rates will help to achieve adequate build rates. Harder rock formations will call for more volume due to higher bit speed and higher power (torque) requirements. Flow rates will probably vary somewhat during each job. Muds should be kept as clean as possible. That is as free from undissolved solids, such as sand, as possible. Liquid has to be misted into the air stream in air drilling so that the rubber/stator section is lubricated and cooled.
12.9.2 Mechanical Components of the 6-3/4 Motor Stabilized Bearing Housing
To change the stabilized bearing housing from one motor to another, break the top of the stabilizer loose from the motor bearing assembly body. The make up torque is approximately 10,000 ft-lbs. Unscrew the stabilizer and slide it off of the motor. Repeat the above step and remove the 7-1/4 O.D. saver ring from the new motor. Screw the 7-1/4 O.D. ring on to the used motor and hand tighten. This acts as a thread protector. Slide the stabilized bearing housing on to the new motor, thread end first. Screw the stabilizer to hand tight. Using rig tongs tighten the housing to 10,000 ft-lbs.
12.9.3 The Orientation Sub (crossover sub at the top of the motor)
Sometimes two motors will go out on a job, one with an orientation sub that has been bored to accept a steering tool adaptor sleeve and the other with no sub or with a conventional crossover sub. To remove the top sub from the motor break the connection using approximately 18,000 ftlbs. of torque. Hand screw the sub onto the new motor and tighten with rig tongs to 18,000 ft-lbs. of torque.
The Adjustable Bent Housing (the oversized lock-nut located approximately 7 to 8 above the drive sub or bottom of the motor)
12.9.4
Place the lower set of vices on the section of the motor just below the lock nut. The upper set of vices will work on the lock nut. Hold the motor with the lower vices and pull with the top vices to break the lock nut. The lock-nut has been torque to 18,000 ft-lbs.
127
Section 12:
Motor Operations
Unscrew the lock nut to the bottom section of the motor. Pull the lower numbered section out until the pin disengages from the upper numbered section. Turn the bottom section of the motor until the desired bend setting are directly opposite each other on the upper and lower sections of the bent housing; i.e., 1.25 and 1.25. Ensure that you refer to the specification sheets with the tool to determine the resultant angles from the set angles on the Black Max motors. Reestablish the pins making sure that the desired settings are directly opposing. Hand screw the lock nut until the hand tight against the lower numbered section. Using the top vices pull on the lock nut until 18,000 ft-lbs is achieved. Reset the steering tool alignment to high side. 12.10 The 2-7/8 Slo-Speed PDM
12.10.1 Parameters:
Hole Sizes: Bit Types:
3-5/8 to 4-1/2 - in extreme cases 3-3/8 and 4-3/4. Tri-cone sealed bearing rock bits, fixed head bits, PDC bits, TSD bits, and natural diamond bits. Liquid: Air: 20 GPM - 80 GPM 90 cu. ft./min. - 360 cu. ft./min.
Fluid Flow:
Flow rates are also the main determining factor as far as drill bit speed and power are concerned. The situations of less volume in soft soils and more volume in harder formation are always a consideration. Solids in liquid drilling fluids and misting a soap-water mixture into the air stream during air drilling are still considerations.
12.10.2 Mechanical Components of the 2-7/8 Motor Adjustable Bent Housing The adjustable steps are the same as for the 6-3/4 adjustable bend housing. The torque for the lock nut, though, is 2,500 ft-lbs. Ensure that you refer to the specification sheets with the tool to determine the resultant angles from the set angles on the Black Max motors.
128
Section 12:
Motor Operations
Crossover Top Sub If the top sub needs to be changed out or moved from one motor to another the torque is 2,500 ft.-lbs.
12.10.3 Positive Displacement Motor Section: (2-7/8) and their tasks.
Top Sub
This sub is actually a crossover sub with a 2-3/8 reg. box connec tion. At the present time Sharewell has not developed an orientation sub to replace the top sub.
Motor Section This section houses the metal rotor and rubber stator as in the 6-3/4 motor section. Connecting Rod Housing In directional bores the connecting rod housing is an adjustable bend housing. In straight hole drilling the connecting rod housing is straight with no adjustment. The connecting rod housing houses the torsion rod that connects the rotor to the drive shaft, changing eccentric rotation into concentric rotation allowing straight line drive.
12.10.4 The Bearing Section
This section contains the on-bottom and off-bottom bearings that allows virtually friction free drilling or circulating, respectively. The 2-7/8 steerable motor does not have a stabilized bearing housing due to the O.D. and amount of metal.
12.10.5 The Drive Shaft and Drive Sub
This section transmits the rotation and power to the drill bit which screws into the drive sub.
12.11 Positive Displacement Motor Sections - and their tasks

12.11.1 Orientation Sub
Locks in the steering tool adapter sleeve. Has a 4-1/2 IF box on top that requires 22,500 ft.-lbs. of torque to make up to the non-magnetic drill collar. This top sub is for river crossings. Straight hole motors will have straight housings, no stabilized bearing housing. The top sub has a 4-1/2 reg. box on top and is not bored for a steering tool adapter sleeve. The torque to make up to a drill collar or crossover is 16,000 ft.-lbs.
129
Section 12:
Motor Operations
12.11.2 Motor Section
This section houses the multilobed metal rotor and the multilobed nitrile rubber stator. This is the power section of the motor drilling fluid displaces the rotor causing it to spin. The more volume pumped the faster the rotor spins and the more horse power produced.
12.11.3 Connecting Rod Housing: (adjustable bent housing)
This section houses the torsion rod that transmits the eccentric spinning motion of the rotor into concentric motion or straight line drive. This spinning motion and power is transmitted to the drive shaft. In directional bores the housing will be an adjustable bend housing. In straight hole drilling the housing will be straight with no adjustment.
12.11.4 Bearing Section: (stabilized bearing housing)
This section houses the bearings and races that allows virtually friction free rotation of the drive shaft. The Black Max bearing section provides sealed bearings. This allows 100% the drilling fluid is to be used by the motor. Also, a sealed bearing does not allow solids to enter the bearing section, there by allowing longer bearing life. There are two sets of bearings, on-bottom and off-bottom bearings. On-bottom bearings are used while drilling. Off-bottom bearing are used during circulation or pulling.
12.11.5 Drive Shaft and Drive Sub
The drive shaft transmits the rotation and power to the drive sub which contains the drill bits. The drive sub and drill bit are the only part on the outside of the motor that one can see turn. The drive sub enables the drill bit to be connected to the motor.
12.12.1 Building Angle Too Slow
Cut the volume being pumped to keep from washing out too badly and to slow the drill bit rpm. Trip out of the hole and set the adjustable bend housing to a more aggressive angle. Make sure that the bend is pointing straight up high side during the slide section. Increase the slide section of each point.
130
Section 12:
Motor Operations
12.12.2 Building Angle Too Fast
Increase the volume being pumped to attempt to increase rpm of the drill bit enough to slow down the build rate. Slide the motor less and rotate more. Slide the motor alternating with the bend 60 to 80 left and the right of high side or visa versa for a few feet of each joint. The build will continue at a decreased rate, but the direction will be changing. Care should be taken due to the hole having some fairly high dog-legs in it from the extreme direction changes.
12.12.3 The Motor Is Drilling Fine But Quits Making Hole All At One Time:
Up the volume being pumped. The formation may have become harder. If sliding try rotating a few feet. Check the mud pump, holding tank volume, etc. If the flow of drilling fluid to the motor is interrupted the motor will not drill.
The Motor Seems To Be Loosing Power And Stalling Out Quicker And The Same Volume Is Being Pumped. The Pumping Pressure Is Higher Than Before
12.12.4
The formation may be getting harder. The bearing package may be going out causing the motor to bind up. Increase the volume of drilling fluid and check the rate of penetration. If the rate of penetration does not increase and the motor continues to stall easily, change motor out.
12.12.5 The Pumping Pressure Increases And Will Not Come Down
The drill bit, motor or drill pipe could be plugged. The hole around the motor or drill pipe may have collapsed stopping circulation. The bearing package may be worn out. If the situation happened all at once and usually during a connection, something plugging off may be the problem.
131
Section 12:
Motor Operations
If the situation was gradual, it may be the bearing package of the motor wearing out until it finally locks up. Bleed the pressure off and start the pump slowly to see if the blockage might wash out. Working the drill string in and out during this process may help dislodge the blockage. Set the weight on drill bit and slowly rotate the drill string. Check for increased torque. If the problem cannot be remedied, change out the motor.
12.12.6
The Rate Of Penetration Drops Off And The Motor Cannot Be Stalled Out. The Pump Pressure Does Not Increase Between Off-Bottom and On-Bottom Pressure Readings:
Try to stall the motor by putting enough weight on the drill bit to cause the drill bit to quit turning. If this cannot be done, the stator-rotor seal has been broken so that the mud flow by-passes the rotor. Change out the motor. Try to determine if there may be something in the hole (key-seat, boulder, etc.) that would not allow the weight to get the drill bit before tripping out the hole. Increase the volume of drilling fluid being pumped. Rotate the drill string to try to get the weight to the drill bit and there by stall the motor. If the motor still cannot be stalled and there is practically no rate of penetration, change out the motor.
12.12.7
The Rate Of Penetration Has Dropped Off, But The Motor Seems To Be In Proper Working Condition
Check the cuttings coming back to see if the formation has changed. The drill bit could be the wrong type. If the formation goes from medium or soft to hard, the rate of penetration may drop to practically nil. The drill bit could be balling up, if the cuttings are of a sticky type of clay. Use a little S.A.P. (chemical) to help keep the clay from sticking to the bit. Increase the volume of drilling fluid being pumped and increase the weight to the bit. The rate of penetration should pick up some until the hard section is drilled through or the drill bit wears out.
132
Section 12:
Motor Operations
Change out the drill bit if the problem is not remedied.
12.12.8
The Pump Pressure Drops 100 Psi to 300 Psi Or More But The Motor And Rate Of Penetration Are Good
The pump pressure will decrease gradually. There may be a hole in the drill string. There may be a mud pump problem. Pump a knot of soft line to see if the pump pressure increases. If it does, there is a hole in the drill string. Trip out of the hole to find the problem.
12.12.9
The Last Resort During Any Performance Problem Is To Trip Out Of The Hole. Exhaust All Solutions Before Changing Out The Motor.
133

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Section 8:

Directional Drilling Systems

Surface Location Systems

8.0 Surface Location Systems

Surface Location Systems

Land Survey Techniques

9.0 Land Survey Techniques

Land Survey Techniques

Land Survey Techniques

Entry Point Datum = 272.5

10.0 Job Site Actions Pilot Hole

10.1.2 Unload and Check Equipment

Directional Drilling Systems

10.5.2 Down Hole Assembly Measurements

1.2 .8 20.7 2.3 27.5 15.0 1.8 69.3

Directional Drilling Systems

Orientation 0 90 180 270 0

H Total 48560 48555 48572 48520 48555

Dip 60.3 60.2 60.3 60.1 60.3

Azimuth 27.3 27.2 27.4 27.0 27.3

Orientation 0 90 180 270 0

H Total 48460 48455 48472 48420 48455

Dip 60.6 60.6 60.7 60.4 60.6

Azimuth 27.8 27.8 27.7 27.3 27.8

10.7.7 Pressure Testing

Present Inclination Present Azimuth 81.0 -80.5 0.5

81.0 271.5 271.5 -271.0 0.5

10.12.5 Tripping Pipe OUT

Compressive Strength (PSI)

Talc Shale Clay Mudstone Gypsum

1 less than 3 1.5 - 2.8 1.5 - 2.8 2

More than 45,000

11.2.1 Tool Selection

11.2.2 Jet Nozzle Sizing

Recommended weights vary with cutter type and tool diameter.

Maximum Recommended Weight, Lbs./Inch Hole Enlarger Diameter

Weight 1000# 1500# 1200# 1400#

12.0 Down Hole Motor Operations

12.9 The 6-3/4 Slo-Speed PDM

Hole Sizes: Bit Types:

12.11 Positive Displacement Motor Sections - and their tasks

12.11.2 Motor Section

12.11.4 Bearing Section: (stabilized bearing housing)

12.12.2 Building Angle Too Fast

Change out the drill bit if the problem is not remedied.

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