Hole geometry

Bit- and casing-size selection can mean the difference between a well that must be abandoned before completion and a well that is an economic and engineering success. Improper size selection can result in holes so small that the well must be abandoned because of drilling or completion problems. The drilling engineer (and well planner) is responsible for designing the hole geometry to avoid these problems.

However, a successful well is not necessarily an economic success. For example, a well design that allows for satisfactory, trouble-free drilling and completion may be an economic failure, because the drilling costs are greater than the expected return on investment. Hole-geometry selection is a part of the engineering plan that can make the difference between economic and engineering failure or success.

General design procedures

The drilling industry’s experience has developed several commonly used hole-geometry programs. These programs are based on bit- and casing-size availability as well as the expected drilling conditions.

Deep, high-pressure wells often require deviations from common geometries. Reasons include:

• Prolific production rates requiring large tubing strings.
• Drilling problems requiring the use of an intermediate string and one or more liners.
• Tension design problems because thick-walled pipe must be used to control burst or collapse.
• Rig limitations in running heavy strings of pipe.

Because deep, high-pressure wells are being drilled with increasing frequency, careful attention must be given to hole sizing.

Bottom-to-top approach

The highest priority in well planning should be developing a design that provides for economic production from the pay zone. Even in exploratory drilling for geological investigations, a large hole may be necessary for thorough formation evaluation. The pay zone should be analyzed with respect to its flow potential and the drilling problems that will be encountered in reaching it.

Flow-string sizing

The flow, or tubing, string must be given consideration relative to its ability to conduct oil/gas to surface at economical rates. Small-diameter tubing restricts, or chokes, flow rates because of high friction pressures.

Completion problems can be more complicated with small tubing and casing. The reduced radial clearances make tool placement and operations more difficult, and workover activities are more complicated.

Typical well designs are shown in Fig. 1. The geometries in parts (a) and (c) use large-diameter tubing. The small tubing string (b) will probably restrict the fluid flow from the producing zone. In addition, the design in (b) will probably require special clearance couplings, whereas parts (a) and (c) could use standard-diameter couplings.

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  Fig. 1—Three hole-size combinations for a well.

Planning for problems

Geological uncertainties may make it difficult to predict the expected drilling environment. For example, crossing a fault into a high-pressure region may necessitate a drilling liner, whereas an intermediate string may be satisfactory if the fault is not encountered. Hole geometries are often selected to allow the option for an additional casing string if required (Fig. 2).

Size-selection problems

Many interrelated size-selection problems must be considered before the final hole geometry is established. These problems primarily relate to casing size and openhole considerations, and they are interrelated with casing design. A working knowledge of casing-design problems influences pipe-size selection.

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  Fig. 2—Planning for a hole geometry that allows for liner usage if needed.

Casing design

The large flow string in Fig. 1 resulted in a 13⅜-in. intermediate string and a 20-in. surface casing. However, these strings may be difficult to design if high formation pressures are encountered. Table 1 shows the pipe required for various conditions on the intermediate string, assuming that a single weight and grade will be used.

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  Table 1-Casing Design Requirement For 13⅜-In. Casing In Fig 1

Tension designs become critical in cases similar to Table 1. The in-air hook load of the string is 887,700 lbf for the worst case shown in the table. If a design factor of 1.5 is used to assess rig requirements, the design weight will be 1,331,550 lbf for derrick and substructure selection. Casing and size selection is affected by:

• Pipe yield
• Connector strength
• Rig ratings

Casing-to-hole annulus

Cementing problems may occur if the casing-to-hole annulus is small. Small clearances around the pipe and couplings may cause premature dehydration of the cement and result in a cement bridge. Cement companies report that this bridging occurs more frequently in deeper, hot wells. These companies suggest a minimum annular clearance of 0.375 to 0.50 in. on each side of the pipe, with 0.750 in. preferable.

Drillstring/hole annulus

The area between the drillstring and the hole creates problems if too large or small. Inadequate hole cleaning may occur if the hole is large. High friction pressures and turbulent erosion may occur in small holes. Large holes normally occur in the shallow depths, and small holes are found in the bottom sections.

Hole cleaning describes the ability of the drilling fluid to remove cuttings from the annulus. The important factors are:

• Mud viscosity.
• Cuttings settling velocity.
• Annular mud flow rate.

The annular mud velocity, Eq. 1 , is usually considered the most important aspect.

....................(1)

where

• v = annular velocity, ft/min
• Q_m = mud flow rate, gal/min
• d_H = hole diameter, in.
• d_DS = drillstring diameter, in.

Mud engineers often use other forms of an annular velocity equation.

....................(2)

where

• v = annular velocity, ft/min
• Q_p = pump output, bbl/min
• V_a = annular volume, bbl/1,000 ft.

The annular volume, in bbl/1,000 ft, can be estimated from the rule-of-thumb guide in Eq. 3.

....................(3)

where

d_H and d_DS = hole and drillstring diameter, in.

As an example, an 8½ × 4½-in. annulus has approximately 52 bbl/1,000 ft of annulus. Many drilling rigs do not have adequate pump horsepower to clean the surface regions of the hole and, as such, rely on high-viscosity-gel plugs to clean the annulus. Example 1 illustrates the hole-cleaning problem.

Example 1

Use the hole geometries in Fig. 1 to determine the required flow rate to achieve an annular velocity of 75 ft/min. In addition, determine the surface horsepower required if the pump pressure is limited to 2,500 psi. Use 5-in. drillpipe for A and C and 4½-in. pipe for B.

Solution.

1. From Fig. 1 , the annular geometries in the largest hole sections are

2. Use Eq. 1 to determine the required pump rate for A.

3. Determine the surface horsepower (HP) requirements if the pressure is limited to 2,500 psi. For A,

Based on results from Example 1, hole geometry C will be difficult to clean because many rigs are unable to deliver 2,905 hp under continuous service. Poor hole cleaning is a common cause of annular solids buildup, plugging, and lost circulation.

Most rigs are HP limited when drilling surface hole. Even though a pump may be rated to 3,000 psi, the maximum flow rate usually will be reached before achieving 3,000-psi surface pressure. Typical pressures for surface hole may be 600 to 1,500 psi even when using two pumps. If the pumps are unable to adequately clean the annulus, well-planning provisions must be made for periodic high-viscosity slurries to sweep the annulus.

Small-diameter holes create problems from turbulent erosion and hydraulics. The resultant problems can be cementing difficulties and poor hole cleaning in the enlarged area.

Hydraulics are complicated in the downhole, small-diameter sections. High friction pressures reduce the available hydraulic cleaning action at the bit and increase the chip-holddown effect on the cuttings. Swab and surge pressures can be large and range from 0.3 to 1.0-lbm/gal equivalent mud weight in small holes when heavy muds are used.

Underreaming

This technique enlarges the hole size in excess of the amount attainable with a drill bit. The underreamer tool has expandable arms with bit cones that can be activated with pump pressure. The important negative aspect of underreaming is that the tool arms are frequently damaged or lost in the hole. It is difficult to retrieve a lost underreamer arm.

This technique does have applications in some areas. One important application involves running a liner in an open hole that might be considered too small without underreaming. For example, a 7⅝-in. flush-joint liner run in an 8½-in. hole may be considered unacceptable (by some companies) without underreaming. A 7.0-in. liner may be an alternative, which would result in pipe-size restrictions in deeper sections.

Casing- and bit-size selection

A casing- and bit-size program must consider the problems described in the previous section in addition to the actual casing- and bit-size characteristics. These include casing inner and outer diameter, drift and coupling diameter, and bit size. A working knowledge of these variables is important for selection of a viable geometry program.

Pipe selection

Casing availability is a priority consideration in hole geometry selection. High-strength casing, often required for deep wells, may have a small (drift) diameter that will influence subsequent casing- and bit-size selection. Unfortunately, supply-and-demand cycles in the pipe industry may control the pipe design rather than engineering considerations.

The casing outer diameter (OD) is available in numerous sizes. The drift diameter, which is smaller than the inner diameter (ID), controls the bit selection for the open hole below the casing. As heavier-weight pipe is required to meet design specifications, the available drift diameter is reduced. A rule-of-thumb that has proved satisfactory in most field cases is to allow 1 in. of wall thickness to achieve a suitable design without resorting to the use of ultrahigh-strength pipe. As an example, 9⅞-in. casing can usually be designed properly if 8⅝-in. drift diameters are allowed.

Hole-geometry-selection approach may dictate the casing drift diameter as the controlling criterion. The options are as follows:

• Try to design the pipe under the specific drift and OD conditions.
• Use high-strength materials.
• Use special drift pipe available from some manufacturers.
• As a last resort, pipe manufacturers can prepare a special pipe design based on minimum drift requirements by enlarging the wall thickness and OD.

The fourth option is occasionally required in hydrogen sulfide environments where low-strength metals must be used.

Coupling selection

Pipe couplings are generally designed to satisfy requirements such as burst, collapse, tension, and sealing effectiveness. However, coupling diameters may be a design guideline in some wells. Table 2 shows the OD of various types of couplings and pipe sizes. American Petroleum Inst. (API) couplings are normally 1 in. larger than the pipe in sizes greater than 7⅝ in.

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  Table 2-Clearances for API and various premium proprietary couplings

Advantages are provided by using premium couplings. These couplings usually have clearances less than comparable API connections and occasionally allow the use of smaller pipe in a well. In many cases, more-expensive premium couplings can reduce the total well cost by allowing smaller pipe and hole geometries. In Fig. 1.b , the hole geometry would not be difficult to achieve if premium couplings were used, whereas clearances might be unacceptable if API couplings were used.

Bit-size selection

Sizing the bit program is dependent on the required casing sizes. Bits are available in almost any desired size range. However, nonstandard bits or unusual sizes may not possess all of the desirable features, such as center-jet or gauge-protection characteristics. In addition, bit selection and availability become more difficult in odd or small bit sizes (less than 6.5 in.).

Table 3 illustrates size availability for Hughes insert-tooth bits. Bit sizes less than 6½ in. restrict bit-type selection. In addition, bit selection is restricted for sizes greater than 12¼ in.

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  Table 3-Size availability for various insert-tooth, journal-bearing bits

Standard bit/casing combinations

Fig. 3 can be used to select casing and bit sizes required to fulfill many drilling programs. To use the chart, determine the casing or liner size for the last size of pipe to be run. The flow of the chart indicates hole sizes that may be required to set that size of pipe (i.e., 5-in. liner inside 6⅛- or 6¼-in. hole).

Solid lines indicate commonly used bits for that size pipe that can be considered to have adequate clearance to run and cement the casing or liner (i.e., 5½-in. casing in a 7⅞-in. hole). The broken lines indicate less-commonly-used hole sizes. The selection of one of these broken paths requires that special attention be given to the connection, mud weight, cementing, and doglegs. Bicentered bits provide more flexibility in bit and hole size.

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  Fig. 3—Casing- and bit-size selection chart (courtesy of Oil & Gas Journal).

Noteworthy books

Mitchell, R. F., & Miska, S. (Eds.). (2011). Fundamentals of Drilling Engineering. Richardson, TX: Society of Petroleum Engineers. SPEBookstore and WorldCat

See also

PEH:Introduction_to_Well_Planning