A mud magnet is a bar magnet that looks a lot like an elongated brick.

They are installed in the return mud line just upstream of the possum belly and the shale shaker.  Their purpose is to collect steel particles from the mud stream. Once or twice each day, the magnet is retrieved, scraped, and the collected particles washed, weighed, and examined.

From visual examination of the particles retrieved from the mud magnet, the casing wear mechanism can be identified.  The four possible mechanisms are (1) galling, (2) machining, (3) grinding, and (4) polishing.

1.  The galling process is shown in Figure 1, and the flakes resulting from this process are shown in Figure 2.  High contact pressure forces the tool joints and casing together in intimate contact.  As the tool joint rotates it is `cold welded’ to the casing.  Further rotation pulls pieces from the casing.  These pieces are later dislodged during further rotation of the tool joint.  This is a very aggressive form of casing wear.

Figure 1: Galling

Figure 2: Galling

The flat flakes shown in Figure 2 are typical of the results of galling wear.

If these flat flakes continue for any length of time, you have serious trouble.

2.  The grinding process is shown in Figure 3, and the particles resulting from this process are shown in Figure 4. Here the drill cuttings (sand) carried by the mud stream roll between the tool joints and casing.  If the contact pressure is high enough, the yield strength of the casing (and sometimes the tool joints) will be exceeded, resulting in surface fracturing of both casing and tool joints.

Figure 3: Grinding

The result of this grinding process, shown in Figure 4, is a metallic powder, varying from coarse to fine.  If you are using `unhardbanded’ steel tool joints, grinding will be the dominant form or casing wear that you will see.

Figure 4: Grinding

Judging the significance of the daily weight of material harvested from the mud magnets is a matter of experience.  I know of no way to relate the daily mud magnet collection to the total daily amount worn from the casing.  Sudden increases of grinding debris are a matter of concern.

One thing: check with the on board geologist.  A sudden increase in the volume collected from the mud magnets may be the result of drilling into a formation containing magnetic minerals – probably one of the several iron oxides. (FeO, Fe₂O₃,  Fe₃O₄, ….)

3.  The machining process is shown in Figure 5, and the metallic strings harvested from the mud magnets are shown in Figure 6. This wear results when the tool joints are hardbanded with an alloy containing tungsten carbide particles.  The softer base alloy wears away, leaving the carbide particles exposed.  These particles scrape material from the casing, much as a rasp removes material.

Figure 5: Machining

Figure 6: Machining

Carbide hardbanded tool joints are no longer run in casing, although they offer excellent protection for the tool joints.  If cuttings such as these appear in the material harvested from the mud magnets, you have a serious problem.

4.  The polishing process is shown in Figure 7.  Here the abrasive particles are imbedded in the surface of an elastic supporting material such as pitch, paper, beeswax or rubber.  This is the process used to erase the results of grinding from an optical surface.  In the oil field, this wear results when rubber pipe protectors are run.  Instead of a wear groove, polishing will result in a mirror finish stripe running axially along the inner wall of the casing.

If you wish to use pipe protectors to protect intermediate casing, it is suggested that the first bit run out of casing be run without the protectors.  This will allow the tool joints to wear away the layer of oxidation and mill scale from the area of the casing where the pipe protectors will contact the inner wall.  If this is not done, the friction factor between the pipe protectors and oxide layer will be so high – 0’5 to 0.8 – that it may be impossible to rotate the drill string.  After the mill scale and oxide layer is removed from the casing, the friction factor between rubber protectors and casing can be as low as 0.1.

Figure 7: Polishing

If it weren’t for the chemical and thermal limitations of the rubber protectors, they would be the ideal means to minimize casing wear.

I have no pictures of the very small metallic particles which result from the polishing process. They are similar to the grinding debris shown in Figure 4, but much smaller.

With the results of the directional survey added to the drilling program covering the measured depth interval from intermediate casing seat to the next casing point, you have enough information to run CWPRO and to determine the significance of the results. Casing wear analysis run at this time will allow you to spotlight possible wear problems in time to take proactive remedial action.

I have employed a procedure which determines the location and estimates the seriousness of potential casing wear problems. A sample of the significant data from such a procedure is shown in Figure 1 and 2. The procedure is as follows.

Run CWPRO with 3 different wear factors, such as, in this example, 0.5, 5.0 and 10.0. This will cover the normal range to be expected from steel tool joints and steel casing running in an unweighted water based drilling fluid.

Looking at the three casing wear vs. measured depth plots, the highest casing wear values occur at about 2,000 ft. measured depth.

Figure 1: Casing Wear for Various Wear Factors

Figure 2: Critical Casing Wear Values

If there was no excessive casing wear associated with the wear factor = 10.0, you probably will have no problems.

However, in the example shown in Figure 1 and 2, casing wear associated with a wear factor of 10 is drastic.

Since WF 10.0 is at the upper end of expected wear factors associated with steel casing and tool joints running in unweighted water based mud, and since there is excessive (disastrous !) casing wear associated with the wear factor = 10.0, you must look at the casing wear predicted for the wear factor = 5.0, and hope that the results are more favorable.

If there is no excessive casing wear associated with the wear factor = 5.0, you probably have no problems, but proceed with caution.

What is ‘excessive casing wear’? This you should decide before you run the casing wear analysis.

The casing wear predicted for the wear factor = 5.0 is 94.7%. This is undoubtedly ‘excessive’.

Therefore, you look at the casing wear predicted for the wear factor = 0.5. This is about the smallest wear factor that you can expect from proprietary tool joints and steel casing run in an unweighted water based drilling fluid.

1. Add lubricant to water based mud;
2. Install proprietary hardbanding on tool joints;
3. Consider using rubber pipe protectors; and/or
4. Use downhole motors. (This reduces total drillstring rotations. This doesn’t reduce the wear rate, but it does reduce the total wear volume.)

If there is excessive casing wear associated with the small wear factor = 0.5, you need to consider drastic means to reduce the rate of casing wear.  Means to be considered are # 3 and #4 from the list above. At this time, I know of no proprietary hardbanding (#2 on the list) that is associated with a wear factor less than 0.5.

In order to execute the above procedure, you must decide what ‘excessive casing wear’ is. Usually, this is based on consideration of acceptable burst and/or collapse values.

For this example, pictured in Fig.1, we arbitrarily define ‘excessive casing wear’ as being greater than 62 %.

Therefore, in the example shown in Fig.1, casing wear at measured depth of 2,000 ft. is ‘excessive’ for the wear factors greater than 0.5.

If you have a reasonable estimate for the wear factor that will apply to the casing wear system you are considering, you might predict casing wear for the following three values of wear factor: (1) half the expected value, (2) the expected value, and (3) twice the expected value of wear factor. This will predict the expected casing wear values bounded by an optimistic and a pessimistic estimate.

For your information, the dogleg severity at measured depth = 2,000 ft. in this example is 6 degrees per 100 ft.

There are two obvious reasons for running the casing wear program – CWPRO, which are:

1. To anticipate and then correct possible casing wear problems: and/or

2. As a post mortem analysis to determine `what happened ?’

Figure 1

What Happened ?

It is far better to anticipate, and then take measures to avoid, the consequences that can result from casing wear. It is also a lot less expensive. If preventive measures are omitted, the following is a sequence of events that can, and have, occurred.

1. As drilling out of casing proceeds, casing wear reduces the wall thickness of a section of the casing.
2. The weakened section ruptures due to the differential pressure between the heavyweight mud in the annulus between the casing and the drill pipe and the formation external to the casing.
3. Drilling mud flows through the casing rupture into the formation.
4. Fluid level in the annulus drops, reducing the hydrostatic pressure at all points in the annulus and open hole.
5. The reduced hydrostatic pressure at (or slightly above) the bit decreases to a value less than the formation pressure.
6. Lightweight formation fluid (oil and gas) can then flow from the formation into the open hole, displacing the heavier weight drilling fluid up and out.
7. This further reduces hydrostatic pressure in the open hole below the intermediate casing seat, resulting in increased flow rate from the formation into the open hole.
8. Formation fluids are expelled from the top of the borehole. This is the characteristic `gusher’ shown in so many pictures.
9. Fairly soon, this `gusher’ can ignite, resulting in a scene similar to that shown in Figure 1.

Therefore, the ideal time to run CWPRO is as soon as possible after the well reaches casing set depth and the results of the directional survey are available. I recommend that you use the raw survey inclination and azimuth data to compute your own values of dogleg severity.

I recommend that you do not accept values of dogleg severity as a function of measured depth that you have not confirmed.

The results of the directional survey are the key ingredients for a casing wear analysis. Everything else is available to be loaded in advance. If you can, get management to authorize 30 ft (or 10 meters) station spacing, rather than the standard (and less expensive) 100 ft (or 30 meter) station spacing, it will give you a more realistic result. As we mentioned earlier in this series, a 3 degree change of borehole direction which takes place uniformly over a 100 foot interval is a lot less liable to produce serious casing wear than is the same 3 degree change which takes place over a 30 ft interval.

So now you have the drillstring specifications, the drilling program from the present casing point to the next casing point – estimated WOB, RPM and ROP values -, and the mud specifications.

What is unknown is the value of the wear factor that applies to your particular casing wear system, unless you have tested the precise casing wear system that will exist in your well. This is quite unlikely.

What we do know are the approximate range of wear factors that apply to various casing wear systems, as listed below:

1. Steel tool joints, steel casings (regardless of grade), water based mud carrying sand: The wear factors for these systems range from about 3.0 to 10.0.
2. Steel tool joints, steel casing (regardless of grade), oil based mud carrying sand: The wear factors for these systems range from about 1.0 to 3.0.
3. Proprietary hardbanding (such as ARNCO 100 XT), steel casing (regardless of grade), water based mud carrying sand: The wear factors for these systems range from about 0.8 to 2.0.
4. Steel tool joints, X – 80 riser steel, water based mud carrying sand: The wear factor for these systems range from about 30.0 to 50.0.

Now, what do we do with all this information? That comes next.

When determining the casing wear to be expected over an interval of the intermediate casing, the lateral load per unit length of this intermediate casing is the key quantity to be determined. CWPRO uses the dogleg severity and the drillstring tension to make this determination.

If a wellbore changes direction over a given interval of its measured depth, this will result in a lateral load being applied by the tool joints to the casing over this interval. The lateral load per unit length over any given depth interval is proportional to the dogleg severity which applies over that interval.

Dogleg severity is determined from the results of the directional survey of the well. In a directional survey, the direction of the wellbore is determined at a series of measuring stations. Using the directions measured at the two ends of a survey interval and the distance between these end points, the wellbore is approximated by a circular arc spanning the distance between these two end points.

Thus, the apparent dogleg is uniformly distributed over the length of the survey interval, as shown in Figure 1.

Figure 1: Apparent Dogleg

However, if all of the change of direction occurs within a small sub interval, as shown in Figure 2, the dogleg severity may be much larger than the apparent dogleg computed as though the curvature was uniformly distributed over the directional survey station spacing.

Thus, the use of a station spacing which is considerably longer than the extent of the curved section of the borehole can result in the prediction of a longer interval of casing wear which is considerably smaller than that which actually exists within the sub interval.

So, use closer station spacing. Standard survey station spacing is 100 ft or 30 meters. For high resolution, 30 ft or 10 meters spacing can be used.

It is impractical to set station spacing less than 30 ft, since the statistical uncertainty of the directions measured at the survey stations approaches the magnitude of the angles needed to determine the dogleg severity of the station spacing interval.

Figure 2: Real and Apparent Dogleg

In the event that a maximum dogleg severity is specified in the well contract, make sure you see the original survey measures, and not a 5 or 7 point running average of the dogleg severities. CWPRO requires original survey measures (inclination and azimuth) as input.

Artificially low values of the dogleg severity as a function of the measured depth in the intermediate casing can result in the prediction of dangerously low values of casing wear.

A numerical example of this problem is shown in Figures 3 and 4. Figure 3 pictures an `S’ shaped dogleg, and Figure 4 is a table showing the dogleg severities as determined by a series of measures based on 100 ft. survey station spacing , and the value of dogleg severity that actually exist within the survey intervals.

Figure 3: S - Shaped Dogleg Measurements

Figure 4: S - Shaped Severity Measurements