Slide and rotate performance cannot be reduced to one lateral ROP. Rotary speed, slide speed, slide footage, directional effectiveness, and final wellbore quality answer different questions. A fair comparison separates the modes first, then reconnects them at the section outcome.
Decompose whole-section ROP
Let \(F_r\) and \(F_s\) be rotated and slid footage, and let \(R_r\) and \(R_s\) be the corresponding ROP values. Drilling time is:
$$t = \frac{F_r}{R_r} + \frac{F_s}{R_s}$$
and the resulting section on-bottom ROP is:
$$R_{section} = \frac{F_r+F_s} { \frac{F_r}{R_r} + \frac{F_s}{R_s} }$$
Whole-section ROP depends on how fast each mode performed and how much footage was drilled in each mode.
Assume both wells rotate at 250 ft/hr and slide at 70 ft/hr, but require different slide footage:
| Well | Rotate footage | Slide footage | Calculated section ROP |
|---|---|---|---|
| A | 90% | 10% | 199 ft/hr |
| B | 70% | 30% | 141 ft/hr |
Well A's whole-section ROP is about 41% higher even though rotary and slide ROP are identical. The difference comes entirely from directional-mode mix.
Identical mode-specific performance can produce different section ROP when the directional-mode mix changes. All data shown are synthetic.
Measure directional work, not slide speed alone
Sliding is generally performed because the well needs directional correction. That may involve:
- increasing inclination,
- decreasing inclination,
- turning azimuth,
- correcting a tendency,
- returning toward plan.
The slide therefore produces two things simultaneously:
-
new hole,
-
directional change.
A slide with lower ROP may still be highly successful if it delivers the required directional correction efficiently. Penetration performance and directional performance are different. Two synthetic slides illustrate the distinction:
| Slide | ROP | Directional response | Footage required |
|---|---|---|---|
| A | 90 ft/hr | Weak | 150 ft |
| B | 65 ft/hr | Strong | 70 ft |
Which slide was better? ROP alone favors Slide A. Total directional execution may favor Slide B. The useful question becomes:
How much time and footage were required to achieve the necessary trajectory change?
That is a more complete directional-performance question.
Slide-yield reconciliation separates achieved build and walk response from coverage; the crossplot shows whether the directional response is repeatable.
Two wells can use identical BHAs yet face different directional workloads. Well A may follow plan with 700 ft of slide, while stronger formation tendency forces Well B to slide 2,000 ft.
If the slide ROP is identical, Well B will still have substantially worse whole-lateral ROP. Is the BHA worse? Not necessarily. Is the driller worse? Not necessarily. The wells may simply have had different directional workloads. This is why crew, BHA, and vendor comparisons should not rank whole-lateral ROP without accounting for directional requirement.
Interpret slide measurements in their own mode
During rotary drilling, \(RPM_{surface}>0\), and a mud motor may add bit speed. During slide drilling, \(RPM_{surface}=0\) while \(RPM_{bit}>0\) because the motor continues rotating the bit. Therefore a comparison such as:
Well A drilled at 120 RPM while Well B slid at 0 RPM
is physically misleading. The second bit was not stationary. Its rotational speed was being generated downhole. A simplified motor-speed estimate is often based on:
$$RPM_{motor} \approx Q \times RPG$$
where:
- \(Q\) = flow rate,
- \(RPG\) = motor revolutions per gallon.
So the relevant rotational context during a slide includes:
- flow,
- motor specification,
- differential pressure,
- motor condition.
This is fundamentally different from a surface-RPM comparison. SPE-186166 identifies several examples of information needed for more complete slide analysis:
- toolface angle,
- BHA build/drop tendencies,
- accurate mud-motor performance specifications.[1]
This is important because slide performance is not just a mechanical cutting problem. It is a controlled directional process. Two slides at identical:
- WOB,
- flow,
- differential pressure
can produce different directional outcomes because of:
- toolface control,
- formation tendency,
- BHA response,
- friction,
- motor behavior.
That is why applying a rotary performance model unchanged to sliding can be misleading. Directional data introduces another statistical complication: toolface is angular. Measurements of \(359^\circ,\ 1^\circ,\ 2^\circ\) have an ordinary arithmetic mean of \(120.7^\circ\), although they are clustered around \(0^\circ\). Toolface statistics require circular treatment because angles wrap at 360°. That matters when evaluating:
- average toolface,
- toolface variation,
- stability around a commanded orientation.
A generic arithmetic average can make excellent toolface control look terrible. This is another example of why slide analytics requires domain-specific data processing rather than ordinary tabular averages.
Reconnect mode performance to the section
SPE-196020 examined more than 300 BHA runs and used BHA modeling and historical data to investigate how factors such as:
- bit characteristics,
- motor geometry,
- stabilizer placement,
- formation
affect directional performance.[2] A BHA with a relatively neutral rotary tendency may hold trajectory with little slide footage. Another may continuously build or drop while rotating and require frequent corrections. A lower whole-lateral ROP can therefore reflect directional tendency rather than cutting performance.
| BHA | Rotary ROP | Slide ROP | Slide footage | Calculated section ROP |
|---|---|---|---|---|
| A | 250 ft/hr | 65 ft/hr | 30% | 135 ft/hr |
| B | 225 ft/hr | 65 ft/hr | 10% | 181 ft/hr |
BHA A drills faster while rotating, yet BHA B delivers the section faster because it requires much less sliding. The preferred BHA depends on the objective, which is why directional performance needs multiple KPIs.
Inspect the decomposed intervals
DrillingMetrics makes the distinction visible by moving from the blended section result to individual slide intervals and then to the measured directional response.
The reconciled slide-interval table links each detected slide with footage, ROP, build, walk, DLS, yield, and directional classification.
Viewed together, these perspectives help separate slower drilling within a mode from the additional directional work required to deliver the wellbore.
Practical comparison workflow
| Step | Engineering action |
|---|---|
| 1 | Classify rotary drilling, slide drilling, and other rig states. |
| 2 | Calculate footage, time, and ROP for each mode. |
| 3 | Recombine the modes to preserve the actual section outcome. |
| 4 | Quantify slide footage, slide percentage, and useful event counts or lengths. |
| 5 | Add planned geometry, inclination/azimuth tendency, and required corrections. |
| 6 | Evaluate slide effectiveness using directional response, toolface, and motor/BHA context. |
| 7 | Evaluate rotary ROP, MSE, mechanical stability, and BHA tendency separately. |
| 8 | Include final wellbore quality before optimizing the mode mix. |
Related technical resources
- The Average Trap: Comparing Drilling Performance With Distributions
- How Survey Interval Affects Wellbore Tortuosity Analysis
- When to Trust a Statistical Drilling Benchmark and When Not To
References
-
Ambrus, A., Ashok, P., Chintapalli, A., Ramos, D., Behounek, M., Thetford, T. S., and Nelson, B. A Novel Probabilistic Rig Based Drilling Optimization Index to Improve Drilling Performance. SPE-186166-MS, SPE Offshore Europe Conference & Exhibition, Aberdeen, United Kingdom, 2017.
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Shahri, M., James, M., Vasicek, A., De Napoli, R., White, M., Behounek, M., D'Angelo, J., Ashok, P., and van Oort, E. Case Studies: Optimizing BHA Performance by Leveraging Data and Advanced Modeling. SPE-196020-MS, SPE Annual Technical Conference and Exhibition, Calgary, Alberta, 2019.