Drilling Method Diagram

Ratio of primary to secondary nozzle areas (R ratio)

Fig. 8.31. Drilling rate and horsepower as functions of nozzle area ratios. After Eckel,52 courtesy AIME.

by wire line operations. Future improvements in bit design are indicated, and savings of 25% of drilling costs may be possible by this method.

8.75 Simultaneous Drilling

This modification involves the simultaneous drilling of two directional wells with a single rig and drilling crew. This technique has reportedly been successfully applied by the Russians in some fields.64 The main saving is again due to reduction of trip time.

The schematic rig layout shown in Figure 8.32 requires an enlarged floor area, two rotary tables, and a special crown block which allows the block location to be readily transferred from hole to hole. As pipe is withdrawn from hole 1 it is lowered into hole 2; hence one hole stands idle half the time. This is a principal disadvantage, as it may cause hole trouble in some areas.

Theriot64 has estimated that 60% of trip time, 80% of cementing time, and 90% of waiting on cement time may be eliminated in this manner by proper timing of these operations. These and other savings may amount to approximately 34% of total rig time for an offshore, directionally drilled well. Application of this method

Slicklin Tools

Fig. 8.32. Schematic rig layout for simultaneous drilling operations. After Theriot,54

courtesy AIME.

Tool ramp side of simultaneous drilling rig

Fig. 8.32. Schematic rig layout for simultaneous drilling operations. After Theriot,54

courtesy AIME.

will, however, depend on the elimination of operational problems and the development of proper equipment. Certainly this is an interesting possibility for certain areas, particularly offshore operations.

Suggested improvements in the basic methods of drilling have utilized either or both of two approaches:

  • 1) Higher energy input at the bit
  • 2) Minimization of nonproductive rig time Economical improvement of either factor offers considerable benefit to the entire industry. None of the methods cited in this section are intended to replace completely the standard method. Some methods, however, are expected to supplement it in certain areas. Continued improvements in the conventional technique make it increasingly difficult for new methods to compete favorably. The success of any drilling method or technique hinges on its ability to minimize total drilling costs as defined by Eq. 8.15:


where CF = average direct drilling and completion cost/ft

Cr = rig operating cost, $/hr tmt = maintenance and trip time, hr D = depth interval Cb = bit costs

CA = auxiliary equipment costs, such as turbodrill, etc. CM = mud costs

Co = completion costs, including casing, cementing, etc. Rp = average on bottom penetration rate, ft/hr

Clearly, CF does not depend onRp only, and it is quite possible to have increases in Rp resulting in over-compensating increases in tmi, CB, Ca, Cc, and/or Cm-The definition of a minimum CF for a given set of conditions is an extremely elusive figure and it is improbable that such has ever been precisely calculated. Attempting to reduce CF is, of course, the primary job of those engaged in the drilling industry, regardless of their capacity.


1. A medium strength formation is observed to drill at 40 ft/hr at W = 24,000 lb and N = 150 rpm. Bit size is 8 in. Assuming adequate bottom hole cleaning and that Eq. 8.4 applies:

  • a) What penetration rate could be attained at W = 36,000 lb? (N = 150)
  • b) At N = 225, RP = ? (W = 24,000)
  1. Assume that WN = 3.6 X 108 rpm-lb is the operating limit for the conditions of Problem 1. Plot the rate of penetration vs W and N for the range 12,000 < W < 60,000 and 60 < N < 300. Show these plots on both cartesian and log-log paper. Assume adequate bottom hole cleaning and that Eq. 8.8 applies.
  2. At what rate would you expect the same formation to drill using a 10 in. bit at:
  • a) W = 24,000 lb
  • b) W = 30,000 lb
  • c) W = 40,000 lb

4. Field tests indicate that under common conditions a dense dolomite section drills according to:

Rp = 3.8 X 10-V-W1'2 ft/hr where w = bit load in lb/in. of diam. If operating restrictions are imposed such that wN = 5 X 105,

  • a) What Rp can be obtained if TV =50 rpm?
  • b) Suppose that crooked hole restrictions cause bit loading to be fixed at w = 5000 lb/in. What reduction in Rp will this cause, based on part (a)? Ans. (b) 16.$,— 10.3/ 16.9 = 39% reduction.

5. A rig has 700 HP available for drilling an 8 f in. hole from 6000 to 12,000 ft. The drill string is composed of: Surface connections: case 3, Figure 7.3

Assume mud conditions of Hughes charts in Chapter 7, and constant maximum pump HP operation.

  • a) Calculate bit horsepower, equivalent single nozzle size, and actual size for 3 nozzles at 10,000 ft for required annular velocities of (1) 100 ft/min (2) 150 ft/min (3) 200 ft/min. Show these data graphically.
  • b) For an annular velocity of 150 ft/min, calculate the equivalent single nozzle size at 6000, 8000, 10,000, and 12,000 ft and show these results graphically.
  • c) Discuss any conclusions you might draw from (a) and (b).

6. In Problem 24 of the previous chapter the method for developing Figure 7.4 through 7.7 was given:

By substituting K = 0.72 X 10~4, /ii = 3 cp, p = 9.5 lb/gal we obtained:

0.58 g'-86L lOOOd4-86

Ap which is the equation used in constructing Figures 7.47.7, where proper average values of dwere used for the various tool joints. This shows turbulent flow pressure loss to be directly proportional to g1-86. Assuming turbulent flow throughout the entire system, show that:

  • a) HP*= Kii2-86, where K i is an appropriate constant for given pipe sizes, etc.
  • b) The sum of drill pipe and drill collar pressure loss may be expressed as

App+Ap, where Lc = length of drill collars of diameter dc Lp = length of drill pipe of diameter dp

7. (a) Using the chart developed by Speer (Figure 8.23) determine proper drilling conditions from following data:

2000 40

3000 60

4000 75

5000 75

(b) What hydraulic HP will allow utilization of optimum w and N? What would be the resulting jRp? Ans. (a) W ~ 4000, N ~ 170, (b) 500 HP, Rp ~ 95 ft/hr.

  1. Suppose that in a hard rock area application of Figure 8.23, balling did not occur, that is, Rp continued to increase nearly proportionally with w until the maximum allowable value was reached. What might then be done concerning pump horsepower? (See Bromell's data in Table 8.1.)
  2. Which of the operations in Examples 8.1 and 8.2 results in the higher impact force on bottom? (See Eq. 8.9.) Will this always be the case? Explain.
  3. Using the same pipe and hole sizes as in Example 8.1 and the mud properties of the Hughes Charts, calculate the optimum flow rate q<> at various depths to 15,000 ft. Keep the same drill collar length and vary pipe length only. Show these data as a plot of g0 vs depth. Discuss the results.
  4. Repeat Problem 10 for a pressure limit of 3000 psig. (See Reference 42 for similar plots.)


  1. Pennington, J. V., "Some Results of DRI Investigations — Rock Failure in Percussion," API Drilling and Production Practices, 1953, p. 329.
  2. 1954 Report. Drilling Research Inc., Battelle Memorial Institute.
  3. Simon, R., Cooper, D. E., and M. L. Stoneman, "The Fundamentals of Rock Drilling," API Paper 826-27-H, Presented Columbus, Ohio, Apr. 1956.
  4. Murray, A. S., and S. P. MacKay, "Water Still Poses Tough Problem in Drilling with Air," Oil and Gas Journal, June 10, 1957, p. 105.
  5. Wuerker, R. G., "Annoted Tables of Strength and Elastic Properties of Rocks," Petroleum Branch, AIME, Dec. 1956.
  6. Cunningham, R. A., "The Effect of Hydrostatic Stress on the Drilling Rates of Rock Formations," unpublished M.S. thesis. Houston, Texas: Rice Institute, 1955.
  7. Murray, A. S., and R. A. Cunningham, "Effect of Mud Column Pressure on Drilling Rates," Trans. AIME, Vol. 204, (1955), p. 196.
  8. Payne, L. L., and W. Chippendale, "Hard Rock Drilling," The Drilling Contractor, June, 1953.
  9. Bredthauer, R. O., "Strength Characteristics of Rock Samples under Hydrostatic Pressure," unpublished M.S. thesis. Houston, Texas: Rice Institute, 1955.
  10. Catalog No. 21, Hughes Tool Company, Houston, Texas, 1955-56.
  11. Gatlin, C., "How Rotary Speed and Bit Weight Affect Rotary Drilling Rate," Oil and Gas Journal, May 20, 1957, p. 193.
  12. Brantly, J. E., and E. H. Clayton, "A Preliminary Evaluation of Factors Controlling Rate of Penetration in Rotary Drilling," API Drilling and Production Practices, 1939, p. 8.
  13. Bielstein, W. J., and G. E. Cannon, "Factors Affecting the Rate of Penetration of Rock Bits," API Drilling and Production Practices, 1950, p. 61.
  14. Speer, J. W., "Drilling Time Reduced 31 Percent," Oil and Gas Journal, Oct. 11, 1954, p. 130.
  15. Eckel, J. R., "Effect of Mud Properties on Drilling Rate," API Drilling and Production Practices, 1954, p. 119.
  16. Wardroup, W. R., and G. E. Cannon, "Some Factors Contributing to Increased Drilling Rate," Oil and Gas Journal, Apr. 30, 1956.
  17. Scott, J. O., "What Those French Turbodrill Tests Show," Oil and Gas Journal, Feb. 11, 1957, p. 121.
  18. Woods, H. B., and E. M. Galle, "Effect of Weight on Penetration Rate," The Petroleum Engineer, Jan. 1958, p. B-42.
  19. Grant, R. S., and H. G. Texter, "Causes and Prevention of Drill Pipe and Tool Joint Troubles," API Drilling and Production Practices, 1941, p. 9.
  20. McGhee, E., "How to Get Your Money's Worth From Your Drill String," Oil and Gas Journal, Oct. 9,1956, p. 133.
  21. Main, W. C., "Discussion of Texter and Grant Paper (Reference 19), ibid.
  22. Crane, F. S., "Drilling Based on Constant Weight-Speed Factor," World Oil, Mar. 1956, p. 142.
  23. Speer, J. W., "How to Get the Most Hole for Your Money," Oil and Gas Journal, Mar. 31, 1958 and Apr. 7, 1958, pp. 90 and 148, respectively.
  24. Woods, H. B., personal communication.
  25. Bentson, H. G., "Rock-Bit Design, Selection, and Evaluation," API Drilling and Production Practices, 1956, p. 288.
  26. Adams, J. H., "Air and Gas Drilling in the McAlester Basin Area," API Paper No. 851-31-N, Presented Tulsa, Apr. 1, 1957.
  27. Cunningham, R. A., and J. G. Eenink, "Laboratory Study of Effect of Overburden, Formation and Mud Column Pressures on Drilling Rate," AIME T.P. 1094-G, presented Houston, Texas, Oct. 1958.
  28. "Effects of Drilling Fluid on Penetration of Rock Bits," Excerpts from Battelle Memorial Institute Report to the American Association of Oil Well Drilling Contractors, in The Petroleum Engineer, Jan. 1956, p. B-85.
  29. Mallory, H. E., "How Low Solid Muds Can Cut Drilling Costs," The Petroleum Engineer, Apr. 1957, p. B-21.
  30. Eckel, J. R., "Effect of Mud Properties on Drilling Rate," API Drilling and, Production Practices, 1954, p. 119.
  31. Cunningham, R. A., and W. C- Goins, Jr., "How Mud Properties Affect Drilling Rate," The Petroleum Engineer, May 1957, p. B-119.
  32. Perkins, H. W., "A Report on Oil-Emulsion Drilling Fluids," API Drilling and Production Practices, 1951, p. 349.
  33. Lummus, J. L., Barrett, H. M., and H. Allen, "The Effects of Use of Oil in Drilling Muds," API Drilling and Production Practices, 1953, p. 135.
  34. Nolley, J. P., Cannon, G. E., and D. Ragland, "The Relation of Nozzle Fluid Velocity to Rate of Penetration with Drag-Type Rotary Bits," API Drilling and Production Practices, 1948, p. 22.
  35. Eckel, J. R., and J. P. Nolley, "An Analysis of Hydraulic Factors Affecting the Rate of Penetration," API Drilling and Production Practices, 1949, p. 9.
  36. Eckel, J. T., and W. J. Bielstein, "Nozzle Design and its Effect on Drilling Rate and Pump Operation," API Drilling and Production Practices, 1951, p. 28.
  37. Heliums, E. C., "The Effect of Pump Horsepower on the Rate of Penetration," API Drilling and Production Practices, 1952, p. 83.
  38. Thompson, G. D., "A Practical Application of Fluid Hydraulics to Drilling in California," API Drilling and Production Practices, 1953, p. 123.
  39. Bromell, R. J., "Bit Hydraulics for Hard Rock Drilling," API Paper No. 906-1-J, Presented Fort Worth, Mar. 1956.
  40. Keating, T. W., Clift, W. D., and J. Cutrer, "Report on Hydraulics of Rotary Drilling," API Paper No. 926-1-F, Presented San Antonio, Texas, Mar., 1956.
  41. Bobo, R. A., and R. S. Hoch, "Keys to Successful Competitive Drilling," Part 5C, World Oil, Nov. 1957, p. 112.
  42. Colebrook, R. W., "Downhole Power Speeds Drilling," Oil and Gas Journal, Nov. 17, 1958, p. 172.
  43. Moore, P. L., "5 Factors That Affect Drilling Rate," Oil and Gas Journal, Oct. 6, 1958, p. 141.
  44. LeVelle, J. A., "An Engineer's Look at Turbine Drilling," The Petroleum Engineer, Oct. 1956, p. B-39.
  45. O'Connor, J. B., "Turbodrills for American Drilling," Monitor, Nov. 1956, p. 2.
  46. Parsons, C., "Drilling by the Turbine Method," API Drilling and Production Practices, 1950, p. 38.
  47. Thacher, J. H., and W. R. Postlewaite, "Turbodrill Development Past and Present," World Oil, Dec. 1956, p. 131.
  48. Rosu, G. G., "Turbine Drilling Systems and Its Application in USSR," World Petroleum, Mar. 1955 and April

1955, p. 84 and p. 38, respectively.

  1. Trebin, F. A. "Turbine Drilling in USSR," Petroleum Time, Oct. 1955, p. 1088.
  2. "New Percussion Drill Shows Great Promise," The Petroleum Engineer, July, 1957, p. B-32.
  3. Topanelian, E., Jr., "The Application of Low Frequency Percussion to Hard Rock Drilling," Journal of Petroleum Technology, July, 1958 , p. 55.
  4. Eckel, J. E., Deily, F. H., and L. W. Ledgerwood, Jr., "Development and Testing of Jet Pump Pellet Impact Bits," Trans. AIME, Vol. 207, (1956), p. 1.
  5. Camp, J. M., Ortloff, J. E., and R. H. Blood, "Wireline Retractable Rock Bits," World Oil, Oct. 1957, p. 190.
  6. Theriot, W. A., "Simultaneous Drilling," Journal of Petroleum Technology, Apr. 1958, p. 13.

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