Drilling Engineering(Drilling Parameters:)

In addition to having a good geological interpretation and show evaluation skills, the Wellsite Geologist must understand how the drilling parameters affect their interpretations of those subsurface formations.
Observation & Interpretation
The drilling parameters that the Wellsite Geologist is primarily concerned with are those affecting the drillstring and mud system. Although they provide useful information for the drilling engineers, they also affect the interpretation of all the geological data collected at the wellsite.
Drilling Parameters:
One of the most useful “real time” geological tools is the rate of penetration. This measure of drillability is dependent upon formation porosity and rock matrix strength. This ROP, when plotted, commonly shows a strong correlation to the Sonic, the SP, and Gamma Ray logs. The ROP is primarily affected by:
• Bit type (Roller Cone or Fixed Cutter) 
• Weight-on-Bit 
• Rotary Speed 
• Pump Pressure 
• Nozzle Size 
• Mud Density
The Wellsite Geologist should be aware that different bit types will drill similar formations differently. When comparing well data, it is useful to compare the IADC classifications of the bits used. In general, longer toothed bits are used in the softer formations. For example, the selection of a short-toothed bit to drill a soft clay formation will lead to bit balling and slow drill rates. If the Wellsite Geologist is called upon by the drilling supervisor to assist in bit selection (particularly PDC bits), since they are usually rated for formation type based on interval transit time, the geologist should relay the standard rock matrix travel times to the drilling supervisor.
Drilling parameters, such as WOB and RPM also affect the ROP, and the Wellsite Geologist should always check to ensure that these parameters have not changed significantly without their knowledge. In the event of a dramatic change in ROP, ensure that the drilling parameters have remained constant, indicating that the cause of the ROP change was due to the formation. When in doubt, treat the change in drill rate as a drill break.
Drilling fluid hydraulics also affect the ROP. Changes in drilling fluid rheology and pump output can enhance drilling efficiency through improved hydraulics. Since pump pressure is a function of pump output, fluid rheology and bit nozzle size, the Wellsite Geologist should be aware of any changes in the mud properties or nozzle sizes.
1.Rotary Speed:
Rotary speed is defined as the rate at which the bit is rotated during drilling operations, and is measured in revolutions-per-minute (rpm). The amount of rotation is governed by three factors:
1. Maximum efficient rate of penetration 
2. Formation compressive strength 
3. Bit type
The general relationship between rotary speed and drill rate is that the faster the rpm, the higher the drill rate. However, there is an inverse relationship between rotary speed and formation compressive strength, with high rotary speeds in soft formations and low rotary speeds in hard formations
2.Weight-On-Bit:
The amount of weight that may be added on any bit is provided by and limited by bit size and the drillstring (especially the drill collars). The Drilling Engineering principles state that “while drilling, the drillpipe above the collars must be held in tension”. If the drillpipe is put into compression, fatigue failure may result with washouts and/or twist-offs occurring.
To determine the weight that can be placed on the bit, four factors are taken into consideration:
1. The weight that can be carried by the collars. This is governed by the length of the collar section and the weight of the collars (lbs/ ft). Normally, about 80-90 percent of the buoyed weight of the collars is used as the “maximum WOB”.
2. The weight necessary to keep the hole within the degree of deviation (vertical, directional, horizontal) required for the well.Governing factors for deviation control are bit type, the formations, rotary speed, the number and location of stabilizers, and the outside diameter of the Bottom-Hole-Assembly
3. The weight carrying capacity of the drill bit. This will vary with the size and type of bit. Fixed cutter bits tend to handle more weight-per-inch than do roller cone bits. The same is true for rotary speed. The working ranges for the various bit types are shown in Figures 4-1 and 4-2.

4. The weight at which the borehole is drilled most rapidly. This is most often determined through “drill-off” tests.

Once the weight carrying capacity of the drill bit has been determined, and the other drilling parameters taken into account (safety factors, hole deviation, etc.), the maximum weight-on-bit for optimum rate of penetration can be determined. For a specified WOB, a certain number of drill collars will be required. This is determined using

         no.of of D.C. singles required=Maximum W.O.B \ D.C.  max x B.F. x L x WT

where:

WOB = weight-on-bit (lbs)

D.C.max = maximum drill collar weight used (%)

B.F. = buoyancy factor of the mud

L = average length of one drill collar (ft)

WT = average drill collar weight (lbs/ft)

Changes in the WOB, when not intentionally changed by the driller, often indicate changes in the formations. The WOB will normally vary proportionally to the hardness or compressive strength of the formation. Soft or unconsolidated formations require little WOB, while hard formations require the maximum amount of WOB.

3.Hookload:

Total hookload represents the weight suspended in the derrick. This weight includes; the drillstring, kelly (if used), elevators, traveling block and drill line. Since all components, except the drillstring maintain a constant weight, a value can be obtained for the drillstring weight, whenever necessary. This value is of prime importance during trips and connections. When tripping out of the hole, the total hookload should decrease by the buoyed weight of the stand removed from the drillstring. During a connection or when tripping in, the total hookload should increase by the buoyed weight of the single/stand added to the drillstring.

Fluctuations in this drillstring weight will be due to the interaction between the drillstring and the borehole.

This interaction may indicate:

• Swelling or sloughing clays/shales, indicating high water loss or an overbalanced situation. This will cause increased overpull (drag) and can impede pipe movement.

• Excessive filter cake build-up on permeable formations

• The drillstring becoming differentially stuck on a permeable formation.

• Junk in the hole, preventing the bit from reaching bottom

• Dog-legs causing the bit to hang up or drag in the borehole

• A hole washout preventing the drillstring from finding the true borehole or the drillstring is hanging up on a ledge.

•A smaller borehole causing the drill collars and stabilizers to come into contact with the borehole

Knowledge of borehole stability, formation pressures and survey data will assist in determining the correct explanation. An up-to-date pipe tally, listing the position of the collars, stabilizers and other specialized subs in the drillstring, and their location in the borehole will give a better idea as to the whereabouts of any problems.

As mentioned earlier, each time a connection is made, the hookload will increase by the buoyed weight (the effect of mud density) of the single. The equation is:

                                            B.W.=(Wt x L) x [1-(0.015 x MW)]

where: Wt = weight of a single/stand (lbs/ft)

            L = length of a single/stand (ft)

            MW = mud density (lbs/gal)

For example:

A 31.50 ft (19.5 lbs/ft) single added to a 13.2 lbs/gal mud.

B.W. = (19.5 x 31.50) x [1 - (0.015 x 13.2)]

B.W. = 614.25 x 0.802 B.W. = 492.63 lbs

4.Standpipe Pressure:

This is the drilling fluid circulating pressure which is necessary to maintain efficient drill rates. It is measured at the standpipe using a pressure gauge.

Inconsistent standpipe pressures, when using fixed cutter bits, may indicate:

In addition, changes in the established pump pressure will generally indicate problems either in the borehole or in the drillstring.

5.Rotary Torque:

Torque is the force created by the drillstring due to its rotation in the borehole. A portion of the torque is generated by the bit, the remainder will depend on the bottomhole assembly and drillpipe. Therefore, torque is a function of the rotary speed and hole conditions. Torque is normally measured in foot-pounds. However, when a diesel electric or SCR rigs are used, the amount of electric power required by the motors to rotate the drillstring is electric torque, measured in amperes.

Relatively constant torque values indicates normal drilling conditions. Two levels reflect formation hardness:

• Low Torque Values - Soft or plastic, homogeneous formations

• Medium Torque Values - Soft to medium hard homogeneous formations

Erratic torque readings can indicate one or more of the following:

• Reaming of the stabilizers

• The bit is undergauge

• Interbedded formations

• Bit balling

• Rotary Speed changes

• Keyseats or doglegs

• Excessive weight-on-bit

• Junk in the borehole

Sporadic or constant increases in torque may indicate:

• A formation change

• Unoptimized bit weight

• Unoptimized rotary speed

• An undergauge bit

• A drillstring washout

• Increasing borehole inclination

• Increasing filter cake thickness

Sporadic or constant decreases in torque may indicate:

• A formation change

• Unoptimized bit weight

• Unoptimized rotary speed

• Decreasing borehole inclination

• Bit Balling

• Decreasing filter cake thickness

6.Drilling Exponents:

A drilling exponent is a method of normalizing the ROP for changes in WOB, RPM, and hole size. A corrected version has functions for ECD and normal formation pressure to take into account differential pressures while drilling. Some mud-logging companies have “second and third generation” exponents to account for tooth efficiency and formation abrasiveness. These drilling exponents are dimensionless.

Changes in exponent values are generally attributed to formation changes, either lithology or porosity. It should be noted that variations in exponent trend may occur through hydraulic action, such as in soft clays where jetting is the main influence on drilling rate. Exponents are generally used as a formation pressure indicator.

The most common drilling exponent is the DXC, and is calculated using;

In standard oilfield units

where:

R = Rate of penetration (ft/hr)

N = Rotary speed (rpm)

B = Hole diameter (inches)

N.P.P. = normal (lb/gal)

ECD = Equivalent circulating density (lb/gal)

W = weight on bit (klbs)

The metric equivalent is:

where:

R = Rate of penetration (m/hr)

N = Rotary speed (rpm)

B = Hole diameter (cm)

N.P.P. = normal (g/cc)

ECD = Equivalent circulating density (g/cc)

W = weight on bit (tonnes)

The normal formation pressure is referenced from the flowline, and is expressed as a gradient. It will always be less than the true formation pressure gradient which is referenced from either the water table (onshore) or sea-level (offshore).