10 15

* After Doty2

tion between the penetration rate and the filtration rate through the bottom of the hole shows that CHDP is the controlling mechanism. Note that the filtration rate while circulating with the clear brine fluid was much the same as with the other fluids, indicating that an effective filter cake was deposited on the sides of the hole. No correlation was found between the API fluid loss and the penetration rate.

In order to obtain the ultra fast drilling rates possible with clear brine polymer drilling fluids, virtually all the drilled solids must be removed when they reach the surface. When drilling in hard rock formations, this requirement can be achieved by desanders and desilters, if efficiently operated, or by sedimentation in large earth pits, as described above in the section on clear brines. As long as gauge hole can be maintained, the sole function of the polymer is to limit filtration into the walls of the hole. Obviously, a non-viscous, zero yield point polymer should be selected since a viscous polymer will prevent efficient separation of drilled solids. Also, low viscosity will maximize bottom hole cleaning and minimize dynamic CHDP. Another consideration in selecting polymers is that certain ones act as friction reducers in turbulent flow (see Figures 5-33 and 9-26) and thus reduce pressure losses in the drill pipe and increase the hydraulic horsepower at the bit.

I.D. Pipe or Tubing

Figure 9-26. Effect of polymers on pressure loss of liquids in turbulent flow. (Courtesy of Brinadd Co.)

I.D. Pipe or Tubing

Figure 9-26. Effect of polymers on pressure loss of liquids in turbulent flow. (Courtesy of Brinadd Co.)

Densities up to 10 lb/gal (1.2 SG) are usually obtained with KC1 or NaCl, up to 11.5 lb/gal (1.38 SG) with CaCl2, and up to 15.2 lb/gal (1.82 SG) with CaCl? and/or CaBr2, but the higher densities are expensive and may not be economically justifiable. Note that only polymers such as hydroxyethylcellulose or hy-droxyalkyl gums can be used with the polyvalent brines.

Clear polymer fluids also permit fast drilling rates in shales. For example, Clark et al29 obtained penetration rates 50% to 100% faster than those in offset wells when drilling in brittle shales in the Canadian foothills with the KCl-poly-acrylamide clear fluid mentioned in Chapter 8. Again, in the full-scale drilling tests mentioned above, Doty28a found that the clear brine drilling fluid drilled the fastest through Pierre shale (a soft montmorillonitic shale) under all conditions except high bit weight combined with high mud pressure. But the use of clear brine polymer drilling fluids in shales is limited by two problems:

1. Dispersion of drill cuttings: makes it difficult to maintain a low enough solids content. Use of a polymer that coats (encapsulates) the drill cuttings will keep the solids content within bounds when drilling in consolidated shales,30 but in soft, unconsolidated shales excessive build-up of solids is very difficult to prevent.

2. Hole enlargement: if the hole enlarges significantly, a viscous polymer, such as Xanthan gum or prehydrated bentonite, must be added to clean the hole. High viscosities and yield points prevent adequate separation of solids at the surface, and again, the solids content becomes excessive. Therefore, every effort should be made to prevent hole enlargement, both by good drilling practice and by the use of one of the shale stabilizing KC1-polymer fluids mentioned in Chapter 8.

When drilling with conventional high solid muds, mud properties have much less influence on penetration rates. Variations in viscosity and solids content have a comparatively small effect on penetration rate, as shown in Figures 9-23 and 9-25. There is no direct correlation with filtration properties (See Figure 9-27),3' although there is a tendency for both to move in the same direction, because both decrease with increase in the colloidal fraction. The only mud property that has a major effect on drilling rate in high solid muds is density (discussed earlier in this section).

When drilling in shales, drilling rates may be improved by the use of muds or mud additives that inhibit bit balling. For this purpose, lime or calcium ligno-sulfonate muds are helpful because they inhibit the softening of the shales. Cunningham and Goins32 found that emulsification of oil increased penetration rates in microbit tests with Vicksburg and Miocene shales (see Figure 9-28), presumably because of decreased bit balling. The use of an aluminum-lignosulfonate chelate to prevent bit balling was discussed earlier in this section.

the compressive stresses surrounding the borehole. Since the tensile strength of rocks is usually small compared to the compressive stresses, it is generally (though not always justifiably) left out of the calculation. The direction of the fracture must be normal to the least principal stress. Except in regons of active mountain building, the least principal stress is horizontal, and therefore an induced fracture is vertical. u As discussed in the section on stresses around the borehole, in Chapter 8, the lease principal stress, a3, is related to the overburden effective stress, S — p^ by a factor kx, the value of which depends on the tectonic history of the geologic region. Therefore, a fracture will be induced when:

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