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Dogleg severities have to be considered at this stage. DLS has to be restricted (especially higher up in the hole) to avoid drillpipe damage, fatigue, and casing wear. This impacts on the directional well design because you will specify a kickoff point depth to reach a known target position. How quickly you build angle will determine the final inclina- tion (i.e., a faster build rate gives a lower inclination) and measured depths of the casings.

This becomes more of a problem the deeper the well is. Say your planned kickoff depth was 1500 ft. You initially want a build rate of 3˚ per 100 ft of drilled hole to a 30˚ inclination. Deeper down, the build section is cased off. Drilling at 10,000 ft TVD (that would be at 11,212 MD) in 121_{/4in hole with 0.65 psi/ft mud, the drillstring tension at the}

kickoff depth could be in the order of 180,000 lbs, using 5 in grade S drillpipe and 8 in collars. (Refer to “Tension due to weight in a deviat-

ed wellbore” in Section 1.4.13, Calculating Axial Loads.) This tension will pull the drillpipe into the inside of the curve and force the drillpipe against the casing. Of course, you will be tripping and rotating while operations continue, which will cause wear on the casing. The higher the dogleg severity, the more the sideforce generated and the greater the wear.

Tool joint damage. This sideforce also imposes a lateral loading on the tool joints that can cause damage; Lubinski suggested a limit of 2000 lbs lateral force to avoid damage to the tool joints. The dog- leg severity for a given lateral force and drillstring tension can be calculated by:

108,000 F

c = —————

pLT

where c is dogleg severity in ˚/100 ft, F is the lateral force, L is half the length of a joint of drillpipe in inches and T is the drillstring ten- sion at the depth of interest. Using a maximum lateral force of 2000 lbs as suggested by Lubinski and assuming 31 ft joints of drillpipe, the DLS causing this lateral force would be (108,000 x 2000) ÷ (3.142 x 186 x 180,000) = 2.05˚/100 ft. From this, it can be seen that our initial assumption about the desirable dogleg severity is ambitious and is like- ly to cause tool joint damage. We can also calculate the lateral force for the initially planned dogleg severity by turning the above equation round, so that:

p x L x T x c F = —————---

108,000

and for a DLS of 3˚, the lateral force F would be 2922 lbs.

In examining these limiting factors, a practical point must also be made. We run directional surveys while drilling, but these surveys inevitably give an average dogleg severity over the interval between survey points. The most common method of calculating the wellpath

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between surveys, “minimum curvature,” assumes a perfect arc between survey points. In practice the actual dogleg severity will be greater in some places than others, imposing a point loading at those places. If the limit for dogleg severity were 2.05˚/100 ft, you could plan on an average 1.5˚ dogleg severity to allow for this variation.

There is also a practical solution to allow higher dogleg severities than the limit calculated above. If drillpipe protectors were to be posi- tioned at the midpoint of each joint of drillpipe, and if the OD of those protectors were similar to the tool joint OD, you would effectively halve the length of the drillpipe joint. The load would be taken by the protectors that would reduce the load on the tool joints. As the factor related to the length of the drillpipe joints L is on the bottom half of the formula, halving the length would double the allowable dogleg severity. Therefore, by using drillpipe protectors, one per joint on drillpipe being rotated through the build section, the allowable DLS will double to just over 4˚. Two protectors per joint, equally spaced at one-third and two-thirds inches along the pipe, will further reduce the load and allow a larger DLS.

Drillstring fatigue. The area of the drillpipe subjected to the sever- est cyclic bending stresses when rotated in a dogleg is where the drillpipe body joins the tool joint. Here the stiffness of the drillpipe changes very quickly between the rigid tool joint itself and the flexible pipe body.

Calculation of fatigue is fairly complicated. Calculations for fatigue limitations of dogleg severity gives greater dogleg severities than the maximum found by calculating for preventing tool joint damage, except at very low drillstring tensions (below about 75,000 lbs or lower). Therefore, as long as doglegs are limited by the 2000 lbs lateral force for tool joint damage, pure drillpipe fatigue is not likely to be a problem.

Reference can be made to the graphs in Section B4 of the IADC

Drilling Manual and also in API RP7G These graphs show the maximum

dogleg severity for commonly used drillpipes. Preston Moore’s Drilling

Practices Manual also has some graphs illustrating fatigue limitations of

dogleg severity. The most commonly referenced paper on the subject is “Maximum Permissible Dog-legs in Rotary Boreholes,” by A. Lubinski. Fatigue failures can occur at other areas on the drillpipe. If the pipe is not sufficiently torqued up so that the shoulders are compressed together, fatigue failure of the pin will occur very quickly. Also, if the

pipe body has internal corrosion, external slip marks, or other damage, the effect of these stress raisers will lower the fatigue resistance of the pipe substantially, and a failure of the body may occur there rather than at the upset to the tool joint.

Casing wear. In addition to tool joint damage and fatigue consid- erations, wear on the casing as a result of lateral forces also has to be considered. Wear from tripping is much less than that from rotating and in medium drillstring tensions in doglegs below 6˚/100 ft, the pipe body does not touch the casing. Therefore, wear arises mainly from rotating tool joints that are pushed against the casing.

Wear is affected by many different factors:

■ _{Contact pressure between the tool joint and casing (depends}

on lateral force and contact geometry)

■ _{Type of fluid in the hole} ■ _{Number of rotations}

■ _{Presence or absence of hard facing, whether it is smooth or not}

and whether it stands proud of the tool joint or not

■ _{Presence or absence of tong marks or other sharp edges that}

would cause abrasion

■ _{Materials in contact}

and may occur as a result of three different mechanisms:

■ _{Two-body abrasive wear—sharp edges on the tool joint act like}

a file on the casing. Produces small cuttings, shiny on one side, like file or lathe cuttings, and very high wear rates.

■ _{Two-body adhesive wear—a galling mechanism where the two}

bodies become friction-welded together momentarily. Produces flakes of metal and moderate wear rates.

■ _{Three-body abrasive wear—solids in the mud become embed-}

ded in rubber protectors and act as a fine abrasive. Produces fine metal powder and very low wear rates.

In new casing on the first bit run, the contact area between tool joint and casing is very small. Wear rate is very high. Since the inside of the casing is worn, contact area will rapidly increase and for the same lateral force, the lateral pressure (in psi) will decrease. The initial

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very high wear rate will quickly become moderate; abrasive wear will decrease as the tong marks on the pipe are worn down and contact pressure drops. After a trip there will tend to be a temporary increase in wear because new tong marks will be present.

The hard banding on tool joints is very important. It must be smooth, hard, and flush with the tool joint. In the “old days” hard banding could be very rough and stood proud of the tool joint—an efficient rotary file. If it is not flush then all of the lateral force is taken on that small area so that contact pressure is extremely high. Never run rough hardbanded tool joints inside casing while drilling.

Dull tong dies will tend to make marks worse on the tool joints as more closing pressure is required to make these dies grip. Apart from the safety aspect of slipping tongs, using dull dies is false economy. Slip and tong dies should be inspected after every round trip and replaced as soon as they become worn.

Casing wear should be monitored by placing two ditch magnets in the return mud flowline or possum belly tank. At the same time each day (usually midnight) the magnets are cleaned off and the metal recovered. Make sure that the mud particles and crud adhering to the metal is removed and then weigh the sample. The daily drilling report should note the daily and cumulative amounts of metal in lbs or kgs. Any sudden increase in the return metal trend should be investigated. Examination of the metal from the ditch magnet should indicate which kind of wear is taking place.

Lubinski proposed a limit of 2000 lbs of contact force, below which damage to tool joints would not be substantial (as discussed above). Wear rates should be moderate below this limit using solids- weighted mud, with smooth hardfacing that is level with the rest of the tool joint OD, and using sharp-tong dies, wear rates should be moderate. Use protectors to reduce lateral forces as described above to below this limit.

If a solids-free mud or brine system is used then wear rates will be much higher. Extra precautions in this case may include using nonrotating protectors (i.e., free to rotate on the drillstring), down- hole motors (to minimize rotating the drillstring), minimizing the dogleg severities and running heavier wall casing over the build and below the wellhead.