Phase-Wise Well Time Estimation - A Complete Engineering Framework for AFE Preparation
Every well overrun begins in the planning phase, not during drilling. The operators who consistently deliver wells on time and on budget share one discipline: they break their well time estimate into specific, measurable activities with individual time drivers, rather than applying a single ROP estimate and a blanket NPT percentage. This article builds directly on our previous guide on drilling time estimation methods and provides the complete phase-by-phase framework from rig mobilization through completion - with the specific time drivers and calculation methods for each activity.
1. Why Phase-Wise Breakdown Changes the Economics
A monolithic well time estimate ("28 days total") hides the distribution of time across activities. When that estimate overruns, you cannot diagnose why or improve the next well. A phase-wise breakdown reveals where the time went, enables real-time comparison of actual vs planned, and provides the data to improve future estimates.
| Phase | Typical % of Total Well Time | Primary Cost Driver | Key Uncertainty |
|---|---|---|---|
| Rig mobilization and spud | 3-8% | Rig move distance, permit delays | Weather, regulatory approval timing |
| Drilling (all sections) | 30-45% | ROP x depth per section | Formation hardness variability, NPT |
| Tripping | 12-20% | Depth x trip speed | Number of unplanned trips (bit failures) |
| Casing and cementing | 8-15% | Number of strings x depth | Cement job failures, WOC time |
| Logging and evaluation | 4-8% | Logging interval x tool speed | Tool failures, repeat runs |
| Completion | 10-25% | Completion type and number of stages | Perforation gun misfires, frac pressure anomalies |
| NPT (all categories) | 8-20% | Historical NPT rate for area | Stuck pipe, equipment failure, weather |
2. Phase 1 - Rig Mobilization and Spud
2.1 Rig Move Time
Rig move time is one of the most predictable phases - yet frequently underestimated because planners use ideal-condition move times rather than historical averages:
Onshore rig move:
Rig down: 2-4 days for conventional land rig
Transport: Distance / average convoy speed (typically 40-60 km/hr with permits)
Rig up: 3-5 days for conventional land rig, 5-8 days for heavy rig
Total typical onshore: 8-15 days for moves up to 100 km
Offshore rig move (semi-sub):
Transit speed: 3-5 knots
Anchor handling: 24-48 hours
BOP test and space out: 24-36 hours
Total typical offshore: 5-15 days depending on distance
2.2 Spud to Surface Casing
The conductor and surface casing sections are the fastest-drilled but slowest-planned phases - planners underestimate the time for regulatory requirements, wellhead installation, and BOP testing:
| Activity | Typical Duration | Notes |
|---|---|---|
| Drill conductor hole and set conductor | 4-12 hours | Driven conductor: 2-4 hours; drilled: 6-12 hours |
| Install surface wellhead and BOP | 8-16 hours | Offshore: add 24+ hours for BOP testing |
| Drill surface hole section | 1-3 days | Fast ROP but large diameter = slow progress in ft/hr terms |
| Run and cement surface casing | 12-24 hours | WOC (wait on cement): minimum 8 hours to 500 psi compressive strength |
| Nipple up BOP and pressure test | 8-16 hours | Regulatory requirement - cannot be shortened |
| Total spud to drilling phase | 3-6 days | Use 4-5 days as standard estimate for onshore wells |
3. Phase 2 - Drilling Phase Breakdown by Section
3.1 Section-by-Section Time Calculation
Each hole section must be estimated independently because ROP, BHA complexity, and NPT probability differ significantly between sections. Use the activity-based format:
Section time = Rotating time + Flat time + Planned NPT allowance
Rotating time = Interval (ft) / ROP_P50 (ft/hr)
Flat time includes all time not rotating:
- Connections: (Interval / Stand length) x Connection time
- Surveys: (Interval / Survey interval) x Survey time
- Wiper trips: Number x (2 x Depth / Trip speed)
- Reaming: Estimated reaming footage x Reaming ROP
- Mud treatments: Number x Treatment time
- BHA inspection: 1-2 hours per BHA run
Detailed flat time calculation for a 12.25" section, 5,500 ft interval, at 9,500 ft total depth:
| Flat Time Activity | Quantity | Unit Time | Total (hrs) |
|---|---|---|---|
| Connections (93 ft stands) | 59 connections | 4 min each | 3.9 |
| MWD surveys (90 ft intervals) | 61 surveys | 8 min each | 8.1 |
| Wiper trips (2 planned) | 2 trips to 9,500 ft | 1,200 ft/hr trip speed | 31.7 |
| Reaming (shale section) | 800 ft estimated | 40 ft/hr | 20.0 |
| BHA inspection and makeup | 2 BHA runs | 2 hrs each | 4.0 |
| Mud treatments and adjustments | 3 treatments | 2 hrs each | 6.0 |
| Total flat time | 73.7 hrs = 3.1 days |
Adding rotating time (5,500 ft / 58 ft/hr = 94.8 hrs = 3.95 days) and NPT allowance (12% x 7.05 days = 0.85 days): Total section time = 9.85 days
4. Phase 3 - Casing and Cementing Time
4.1 Casing Running Time
Casing running speed depends on casing OD, the running method, and whether rotation is used. Standard running speeds:
| Casing Size | Running Speed (ft/hr) | Notes |
|---|---|---|
| 20" conductor | 600-900 | Short strings - fast |
| 13-3/8" surface | 500-800 | Standard power tong makeup |
| 9-5/8" intermediate | 400-700 | Centralizer drag reduces speed |
| 7" production | 300-500 | Premium connections - slower makeup |
| 5" liner | 200-400 | Liner hanger running tool - additional time |
4.2 Complete Casing Job Time Breakdown
Running the casing is only a fraction of total casing job time. Use this checklist for each casing string:
Total casing job time = Pre-job + Running + Cementing + WOC + Post-job
Pre-job: Rig up casing running equipment, inspect casing (2-4 hrs)
Running: Depth / running speed (hrs)
Cementing job: Pump slurry + displacement = typically 2-4 hours
Wait on cement (WOC): Until 500 psi compressive strength = 8-12 hrs for Class G neat
Post-job: POOH with cementing string, nipple up, pressure test = 4-8 hrs
Typical 9-5/8" string at 8,500 ft total time:
Pre-job: 3 hrs
Running: 8,500 / 600 = 14.2 hrs
Cementing: 3 hrs
WOC: 10 hrs
Post-job: 6 hrs
Total: 36.2 hours = 1.5 days
4.3 Cement Bond Log and Remedial Cement
Always include time for cement evaluation in your estimate. A Cement Bond Log (CBL) or Ultrasonic Imager (USIT) run takes 8-12 hours including rig-up and data interpretation. Budget for a 15-20% probability of remedial cement (squeeze job) on critical strings - each squeeze adds 18-36 hours to the well time.
5. Phase 4 - Logging and Evaluation
5.1 Wireline Logging Time Calculation
Total logging time = Rig-up + Logging passes + Rig-down + Interpretation
Rig-up per logging run: 2-4 hours
Logging speed: 1,800-3,600 ft/hr (slow for nuclear, fast for caliper)
Standard triple combo (GR, Res, Density/Neutron) in open hole:
- 1 upward pass at 1,800 ft/hr
- 1 repeat pass for QC (500 ft)
- Total for 3,000 ft section: (3,000/1,800) + (500/1,800) + 3 hr rig-up = 2.9 hours logging + 3 = 5.9 hours
Add for each additional tool suite: 3-5 hours (rig-up + logging pass)
5.2 Wireline Formation Testing (MDT/RFT)
Formation pressure testing and fluid sampling add significant time that is often underestimated in well planning:
| Test Type | Time per Station | Typical Number of Stations | Total Time |
|---|---|---|---|
| Pressure measurement only (MDT) | 10-20 min | 8-15 per well | 2-5 hours |
| Fluid sampling (MDT) | 1-4 hours per sample | 2-4 samples | 4-16 hours |
| Mini-DST (interval test) | 4-8 hours per test | 1-3 tests | 8-24 hours |
6. Phase 5 - Completion Time Estimation
6.1 Completion Type Determines Time Range
| Completion Type | Typical Duration | Key Time Drivers |
|---|---|---|
| Open-hole standalone screens | 2-4 days | Screen running speed, number of screens |
| Cased hole perforated completion | 3-6 days | Perforation runs, tubing running, packer setting |
| Multi-zone with packers | 5-10 days | Number of zones, packer setting operations |
| Single-stage hydraulic fracture | 3-5 days | Frac design, fluid volume, flowback period |
| Multi-stage frac (10-20 stages) | 8-15 days | Stages x (perforate + frac + flowback) per stage |
| Gravel pack (unconsolidated sands) | 4-8 days | Gravel volume, screen running, pack verification |
6.2 Hydraulic Fracturing Stage Time Calculation
For multi-stage frac completions, use this per-stage time breakdown:
Time per frac stage = Perforation + ISIP wait + Frac pumping + Flowback + Plug setting
Perforation run: 2-4 hours (wireline rig-up + run + fire + POOH)
ISIP wait (instantaneous shut-in pressure): 30-60 minutes
Frac pumping: Total fluid volume / pump rate (typically 60-120 min for moderate stages)
Controlled flowback: 2-4 hours minimum
Plug setting (plug and perf): 1-2 hours per plug
Typical 15-stage horizontal well:
Per stage: 8-10 hours average
Total frac time: 15 x 9 = 135 hours = 5.6 days
Add rig-up/rig-down and contingency: total = 7-8 days
7. Building the Master Well Schedule - Putting It All Together
7.1 The Complete Phase-Wise AFE Time Summary
Using a 12,500 ft MD horizontal HPHT well as the example, pulling together all phase estimates:
| Phase / Activity | P50 Days | P90 Days | Key Uncertainty |
|---|---|---|---|
| Rig mobilization and spud | 4.5 | 6.5 | Permit delays, conductor refusal |
| Surface section (17.5") + casing | 3.2 | 4.5 | Lost circulation, cement bond |
| Intermediate section (12.25") + casing | 9.9 | 14.2 | Hard stringers, shale instability |
| Production/reservoir section (8.5") + liner | 8.4 | 12.6 | HPHT tool failures, narrow MW window |
| Wireline logging suite | 1.8 | 2.8 | Tool failures, repeat runs |
| Formation testing (MDT + 3 samples) | 1.5 | 2.5 | Sampling contamination, repeat stations |
| Completion (15-stage frac) | 7.5 | 11.0 | Screen-out, pressure anomalies |
| NPT (12% productive time) | 4.4 | - | Included in P90 estimates above |
| TOTAL | 41.2 days | 54.1 days | P90-P50 = 12.9 days x $120k/day = $1.55M risk reserve |
7.2 Real-Time Progress Tracking - Actual vs Planned
The phase-wise estimate becomes a live management tool when tracked daily against actual progress. The key metric is not whether the well is ahead or behind schedule - it is whether the variance is driven by ROP performance or NPT. These have completely different responses:
- ROP underperformance: Investigate bit performance, drilling parameters, and formation - operational response possible
- NPT overrun: Identify cause category (stuck pipe, lost circ, equipment) - drives lessons learned and future estimate improvement
- Phase milestone variance: If actual casing running time exceeds estimate by 20%+, investigate running tool performance and centralizer drag
Conclusion
A phase-wise well time estimate is not administrative overhead - it is the engineering framework that allows you to manage a complex, multi-week operation against a quantified plan. The $1.55M risk reserve calculated for the HPHT well example above is not a guess or a contingency percentage - it is a quantified P90-P50 gap derived from activity-based estimates and offset well statistics. That level of rigor allows the engineering team to defend the AFE, manage the budget in real time, and build a post-well database that continuously improves future estimates.
The teams that implement this framework consistently find that their actual well times converge toward their P50 estimates over successive wells - because the discipline of breaking down the estimate forces them to understand and manage each activity, rather than reacting to surprises after they occur.
Want to access our complete well time estimation spreadsheet with phase-by-phase breakdown and AFE preparation template, or discuss time estimation for a specific well type? Join our Telegram group for well planning discussions, or visit our YouTube channel for step-by-step tutorials on AFE preparation and well time estimation.
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