Bit Records

An excellent source of offset drilling information is the bit record. It contains data relative to the actual drilling operation, A typical record for a relatively shallow well is shown in Fig. 2-5.

The heading of the bit record provides information such as the following;

  • operator
  • contractor
  • rig number
  • well location
  • drillstring characteristics
  • pump data
  • I i fTn r q wo
  • 1 6o..VU^.r.xOiL K 1.31
  • gbfo HUGHES BIT RECORD

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Fig. 2-5 Bit record for a shallow well

In addition, the bit heading provides dates for spudding, drilling out from under the surface casing (U.S.), intermediate casing depth, and reaching the bottom of the hole.

The main body of the bit record provides the following details:

  • number and type of bits
  • jet sizes
  • footage and drill rates per bit
  • bit weight and rotary operating conditions
  • hole deviation
  • pump data
  • mud properties
  • dull bit grading
  • comments

The vertical deviation is useful in detecting potential dogleg problems.

Comments throughout the various bit runs are informative. Typical notes such as "stuck pipe" and "washout in dnllstring" can explain why drilling times are greater than expected. Drilling engineers often consider the comments section on bit (and mud) records just as important as the information in the main body of the record.

Bit grading data can be valuable in well planning if the operator assumes the observed data are correct and representative of the actual bit condition. The bit grades can assist in the preparation of a bit program for the prospect well by identifying the most (and least) successful bits in the area. Bit running problems such as broken teeth, gauge wear, and premature failures can be observed and preventive measures can be formulated for the new well.

Drilling Analysis. Bit records can provide significantly more useful data if the raw information is analyzed. Plots can be prepared that detect lithology changes and trends. Cost-per-foot analyses can be made. Crude, but often useful, pore pressure plots can be prepared.

Raw drill-rate data from a well and an area can detect trends and anomalies. Fig. 2-6 shows drill-rate data from a well in South Louisiana. A decreasing drill rate is expected as shown.

Sudden changes in the trend might have suggested some anomaly, as in Fig. 2-7, This illustration is the composite drill rates for all wells in a South Louisiana township and range. The trend change at approximately 10,000 ft was later defined as the entrance into the massive shale section,

Cost-per-foot studies are useful in defining optimum, minimum-cost drilling conditions. A cost comparison of each bit run on all available wells in the area will identify the bit(s) and operating conditions that yield minimum drilling costs. The drilling engineer provides his expected rig costs, bit costs,

I.IELL 1 J. D. S1TTIG MC. 1 OPERftTDPr :TDHf Dil L DHPW1V

TTHTEI LS TOUrTHIPi 7'. PSHGE 1 ]U JECTItlN" £6

ft +---------+---------+---------+---------*■-------

Fig. 2-6 Raw drill rate data from a South Louisiana well (Courtesy of Adams and Rountree Technology)

Table 2-1 Average Trip Times

Hole (Bit) Size, in.

Depth,

Small

Medium

Large

ft

(< 8,75)

(8.75-9,875)

(> 9.875)

2,000

1.5

3.0

4.5

4,000

2.5

4.2

5.75

6.000

3.5

5,4

7.0

8,000

4.7

6.5

8.0

10,000

5.8

7.25

9.0

12,000

7.0

8.25

10.25

¡4,000

8.25

9,25

11.50

16,000

9.75

10.25

12.50

18,000

11,00

l 1.25

13.75

20,000

11.8

12.25

15.0

0 +---------+------------------+---------+---------T---------+

a 30

60 ISO 150

PRILL BATE <FT HP>

Fig. 2-7 Composite drill rate data for a South Louisiana region. A significant trend change is observed at approximately 10.000 ft.

and assumed average trip times. The cost-per-foot calculations are completed with Eq. 2.1;

Where:

$/ft = cost per foot, dollars CB = bit cost, dollars CR = rig cost, dollars/hr Tb = rotating time, hr Tx = trip time, lir Y = footage per bit run

A cost-per-foot analysis for Fig. 2-5 is shown in Fig. 2-8.

Trip times should be averaged for various depth intervals. Several operators have conducted field studies to develop trip-time relationships (see Table 2-1). The most significant factors affecting trip time include depth and hole geometry, i.e., number and size of collars, and downhole tools. Table 2-1 can be used in the cost-per-foot equation (Eq. 2.1).

1,000

2,000

3,000

4,000

Q 5,000

6,000

7,000

8,000

9,000

The interval cost from 0-8,100 ft ¡s 385,318

Fig. 2-8 Cost per foot plot for the bit run in Figure 2-5

Example 2.1

Calculate the cost per foot and the cumulative section costs for the following data; assume a rig cost of $12,000/day.

Depth

Depth

Rotating

Bit

In, ft

Out, ft

Time, hr

Cost, $

Well A

6,000

7,150

23

1,650

7,150

8,000

20

1,650

Well B

6.000

8,000

42

2,980

Determine which drilling conditions, Well A or Well B, should be followed in the prospect well. Use a 9.875-in. bit.

Solution:

1. The hourly rig cost is $500. Trip times from 7,150 and 8,000 ft are 6.0 hr and 6.50 hr, respectively.

2, The cost per foot for Bit #1 on Well A (6,000-7,150) ft is:

Bit # 1 $14.04/0 X 1,150 ft = $16,146.00 Bit #2 $ 17.53/ft x 850 ft - $14,900.50 Total = $31,046.50

4. The cost per foot for Well B is:

The section cost is $27,230. 5. Since the cost per foot is lower in Well B, the drilling conditions from Well B should be implemented on the prospect well.

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EQUIVALENT MUD WEIGHT RPh-

FORMATION PRESSURE >PPG> ♦

FRACTURE GRADIENT WG..- +

Fig. 2-9 Formation pressure (and fracture gradient) plot as calculatcd from the dt. exponent example; fracture gradient plot shown for illustrative purposes (Courtesy of Adams and Rountree Technology, Inc.)

The ¿.-exponent method of pore pressure calculations has been applied successfully on bit records. Although the quantitative results should be viewed with caution, the method is useful in many cases. The quality of the results increases in formations with fewer sand sequences (cleaner shale). A variety of pressure prediction techniques are covered in Chapter 3. The data required must be gathered from offset well records (Fig. 2-9).

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