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Bit Selection For Drilling Oil & Gas Wells Guide & Hints

Bit Selection For Drilling Oil & Gas Wells

The Importance of Drilling Bit Selection

Optimum ROP and Durability

Drilling Bit selection commonly involves choosing a bit that offers the right balance between durability and Rate of Penetration. We cannot get the maximum rate of penetration and maximum durability in one bit. The right balance between the two will yield an Optimum ROP and an Optimum Durability for the application.

Avoiding Catastrophe

It is not sufficient to select a bit that seems to offer the desired balance between ROP and durability. We must also be confident that there is little likelihood of major bit failure. We need to be assured that the risk of cone loss through early bearing failure is acceptably low, or that an expensive PDC bit will not be destroyed in a hostile formation before reaching its target.

Maintaining Gauge Hole

The bit should be capable of maintaining the gauge hole. If it does not, then the next bit will be subject to wear and abnormal loading before it ever cuts fresh formation. It may even be damaged if adequate care is not taken when running in the hole. If the under gauge bit is run at the end of a section, it may be difficult to run casing.

Directional Responsiveness

The proportion of directional wells being drilled is rising steadily. The complexity of these wells is also on the increase, while the precision required of the well path becomes ever more demanding. The selected bit has to deliver directional responsiveness that will aid the directional driller, not hinder him.

Most directional wells make use of downhole motors. Rock bits must be able to tolerate the higher RPM’s these may deliver, especially when used in conjunction with the top drive or rotary table.

Cutting Structure Integrity

The chosen bit must withstand variations in formation character and applied drilling parameters that might tend to damage the cutting structure. A durable cutting structure may be destroyed very rapidly, even at the start of a run, if the wrong drilling bit selection is made.

Drilling Cost & Bit Selection

So, we have seen some of the key factors that make bit selection so important. Varied as they are, they have a single thing in common:

Each has a cost. If the selection process is effective, the cost will be held to a minimum. If poor choices are made, costs will rise (check also oil well drilling well cost per foot). Therefore, drilling bit selection is primarily an economic issue, yet, as we shall see, it has little to do with bit price.

The Bit Selection For Drilling Sequence

This is the sequence to be followed in bit selection:

  • Define the Objective.(First, we must understand what we want the bit to do, so we define the objective of the application.)
  • Gather Data. (we seek out similar applications and gather relevant data.)
  • Analyze Actual Performances. (Then we examine the performances of bits in these settings and assess the geological data and set a baseline of performance.)
  • Identify Options. (Several options should now be obvious, some of which have been tried, and some of which are suggested by the analysis and by the shortcomings of what has been tried so far. Assess the full costs of each of these options and select the one offering the lowest cost per foot.)
  • Decide on Basis of Probable Cost/Foot.

Defining the Objective

We ask ‘What do we want the bit to do?’, so we can evaluate bit performances in similar applications. The questions we ask here relate directly to the data we have gathered from offset wells. There are four major areas of interest:

  • Lithology
  • Interval
  • Direction
  • Other (Mud, reaming, drill out etc.)

Lithology In Drilling Bit Selection

What kinds of rock are present?The fundamental question: the starting point for our inquiries.  
What variations do the rocks exhibit?Bit performances, as measured by R.O.P., run length or dull condition, vary considerably, even through rocks that are supposedly the same. Such variations can often be related to differences in lithology. There are limestones and there are limestones!
Are the rocks abrasive?Abrasive rocks are punishing on drill bit conditions. In consolidated, abrasive rocks PDC bits suffer impact damage, tooth bits wear rapidly, bearing seal life is shortened, gauge wear is rapid.
Are they uniform or heterogeneous?All drill bits benefit from drilling in a uniform lithology. Changes from one rock type to another place stress upon the cutting structure and, in roller cone bits, upon the bearings. In these circumstances, individual teeth, cutters or inserts experience high peak loads. Damaging vibration may be initiated during the transition.

Compressive rock strength can be derived from log data in a number of similar ways. The basic requirements are gamma-ray, sonic, and mud logs. The compressive strength of the rock is related to the sonic travel time through a series of equations in which the constants are modified by the lithology.

Young’s Modulus of ElasticityE=[B/Ts2x(3xTs2-4xTc2)/(Ts2-Tc2)]x k x1010
B = Bulk density – log derived value
Ts = Shear Travel Time – calculated with an adjustment reflecting grain size
Tc = Sonic Travel Time – log value
k = constant
Clay FractionFrom the gamma-ray values, we can determine the shale volume or clay fraction. Again, the constant in the equation is dependent upon the rock character, in this case, the extent of its compaction.

Gamma Ray Index
Gi = [G – Gc]/[Gsh – G]

Shale Volume (Clay Fraction) Equations
Cfo = 0.33 x [2(2.0 x Gi) – 1.0]
Compressive StrengthArmed with this Clay Fraction and the Young’s Modulus for the rock, we can compute an in situ compressive strength according to this equation.

CS = [a x (1 – Cf + b x Cf )] x E
The ProcessUsing a typical Rock Strength Analysis program we proceed through a number of steps. From mud logs and wireline data, we select an interval that contains no more than three distinct rock types. We evaluate and quantify the gamma-ray values that distinguish these rock types. The program then examines each data interval, determining the lithology from the limits we have defined for gamma-ray readings, calculating E, Young’s Modulus, clay fraction, and finally the compressive strength of the rock.

The result may then be plotted along with some of the original data. From experience, we know what bit types will be required for particular rock strength values. Note that the peak values encountered, perhaps, only in thin stringers, can be as important as the overall background values of rock strength.  
Very Low Strength< 4,000 psi gumbo shales soft shales claystone, loose sands
Low Strength4,000 – 8,000 psi Chalk, argillaceous sandstones, claystones, soft shales evaporites, soft siltstones  
Medium Strength8,000 – 16,000 psi Conglomerates, sandy, and chalky limestones marls, medium to medium-hard sandstones hard shales, evaporites, soft siltstones  
High Strength16,000 – 32,000 psi hard stringers, hard dolomites, crystalline limestones, hard (brittle) shales, hard sandstones, soft siltstones
Very High>32,000 psi very fine, tight sandstones, chert, quartzite, igneous rocks, metamorphic rocks
Typical Rock Strengths

The concept of rock strength computation is a valuable one in the drilling bit selection process. We should be aware of the limitations it suffers from.

The calculated values depend upon the correct identification of lithology on a foot-by-foot basis. This in turn depends upon the judgment and experience of the analyst. PDC bits are greatly affected by the abrasiveness of the formation. This technique provides no measure of that. As with all offset data, we cannot know how closely the analyzed well or wells will be in character to the planned well.

Despite this, the data can give us valuable insight into appropriate bit types. Broad guidelines are suggested in this table. The bit selection process in drilling can be improved when combined with the other forms of offset data we shall discuss in the next lecture.

  • Light Set 1,000 – 15,000
  • Medium Set 10,000 – 20,000
  • Heavy Set 15,000 – 30,000
  • Ultra Heavy Set 15,000 – 40,000 Diamond 35,000 – 80,000

Direction

We need to know what directional demands will be placed on the bit.

  • Will we turn; build; drill a tangent section; drop angle; drill horizontally; or,
  • will this be a vertical well?
  • Or will there be a combination of some of these well profiles trajectory during the run?
  • In addition to what we are doing directionally, we need to know whether our builds or turns are gentle or hard.
  • What build rates will we seek achieve?
  • What will be the dog leg severity?
  • Once these facts are established, we must find out how we shall do it.
  • The details of the BHA, the mud motor type (e.g. is it low speed-high torque, how many lobes), the drive type (rotary or top drive) should be determined.
  • On directional assemblies, the bend angle of the motor housing is very important – the higher the bend angle the greater the stresses on the drill bit.
  • What proportion of the time do we anticipate sliding versus rotating? (Unwelcome stresses are greater with off-center rotation on a bent housing than when sliding.)
  • The combined down-hole and surface rpm is of special importance for roller cone bits as it impacts on the bearing life. It is also important for the cutting structure of all bits – high rpm’s in hard formation are often damaging.

Interval

Next, we look at the interval we require the bit to drill. We want to match the durability of our selected bit to the length, and difficulty, of the section. [The difficulty of the section, in this context, is defined by the other two factors we have looked at – lithology and steering requirement.

Long IntervalsTraditionally we would expect that longer intervals would demand bits that are more durable. An alternative, not considered sufficiently often, is to use more bits. Let’s look at an example. Work through the example. In this instance, using two bits is a less expensive option than one, because we gain in ROP more than we lose in durability. The extra trip costs less than the time we save by drilling the hole faster.
Short IntervalsShorter intervals can benefit from the use of a more aggressive cutting structure. For example, if an insert bit is pulled short of section TD for some reason – say, rig problems. It could have completed the interval, but it is worn and we prefer not to re-run it. If the remaining interval is short we may not need to run back in with the same type of insert, but go to a more aggressive one. This will yield a higher ROP, or even to a mill tooth bit, that will be faster and probably less expensive.  

Other Factors

Finally, we look at the miscellaneous category. The miscellaneous tag does not mean the items it contains are unimportant. Sometimes they are vital in drilling bit selection

Mud TypeMud type: for fixed cutter bits this is critical. Many bit designs will not function, or function very poorly in water-based muds in particular formations. To properly select a PDC bit we must know the mud type that will be used. We have seen that run lengths are rarely long enough for oil and synthetic muds to affect elastomer seal elements, but that silicate muds may reduce seal life
Reaming  Drill bits were not designed for reaming. Reaming loads the bit in a quite different way to drilling on the bottom. This stresses both cutting structures and bearings. We need to know if the bit is likely to have to do much reaming in the application, and if so how hard this will be. A few meters at three or four points running in the hole, with light weights applied, is not the issue. We are interested in long, hard intervals that take an extended time to ream. These will take their toll of the bit and reduce its ultimate performance.  
Drill out  Drilling out can be a problem for any bit: non-rotating rubbers rotate, PDC drillable shoes cannot be drilled by PDCs. Be aware of what components will be in the casing string. Select the bit accordingly.  
Junk  How much? What kind? Is it on the bottom? What size? What does it cost us to make a dedicated junk run? What does it cost us if we don’t? If we must, a short-toothed mill tooth bit is the best conventional solution, otherwise, if the problem is severe a junk mill or generic term – escapes me right now  
Critical Factors  When we have looked at all these characteristics of the planned well it is timely to consider which are critical for this specific application. For example, the key elements in the 17 ½” section might be that we have to build from vertical to 50° over a long interval.  

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