Why Well Costing is the Backbone of Every Drilling Decision
In my experience working on drilling projects across different environments, one truth stands out consistently: you can have the best engineering team in the world, but if your well costing is off, the project fails. Well costing is not a finance department exercise - it is a core engineering discipline that every petroleum engineer must master.
This article breaks down the fundamentals of well costing, explains how costs are structured across drilling phases, and shares real calculation frameworks you can apply directly to your projects.
What is Well Costing? A Working Definition
Well costing is the process of estimating, tracking, and controlling all expenditures associated with drilling, completing, and abandoning a well. It spans the entire well lifecycle - from pre-drill planning to post-production plug and abandonment (P&A).
A typical onshore development well in West Africa costs between $3M and $8M USD. A deepwater well in the Gulf of Mexico can exceed $100M USD. These numbers make it clear: cost control is not optional.
The 5 Major Cost Categories in a Drilling Project
Understanding cost structure is the first step to controlling it. Here are the 5 categories every drilling engineer and project manager must know:
1. Tangible Costs (Capitalized)
These are physical, recoverable assets that retain value after drilling:
- Casing and tubing strings
- Wellhead equipment
- Downhole completion equipment (packers, perforating guns)
- Pumps and surface facilities
Typical share: 20-35% of total well cost
2. Intangible Drilling Costs (IDC)
These are non-recoverable service costs consumed during drilling:
- Rig day rate (the largest single cost driver)
- Drilling fluids and chemicals
- Cementing services
- Logging While Drilling (LWD) / Measurement While Drilling (MWD)
- Directional drilling services
Typical share: 50-65% of total well cost
3. Completion Costs
Costs to bring the well into production:
- Perforation and stimulation (hydraulic fracturing, acidizing)
- Sand control (gravel packing, screens)
- Production tubing installation
4. Facility and Hook-up Costs
Connecting the well to the production network:
- Flowlines and manifolds
- Wellhead connections
- Instrumentation and safety systems
5. Contingency and Invisible Lost Time (ILT)
The most underestimated category. Industry standard is to budget 10-15% contingency on top of the base estimate. ILT includes:
- Waiting on weather (WOW)
- Equipment breakdown time
- Stuck pipe incidents
- Cement failures requiring remediation
How to Build a Well Cost Estimate - Step by Step
Here is the framework I use when building a well cost AFE (Authorization for Expenditure):
Step 1 - Define the Well Objective and TD
Total Depth (TD), formation targets, and wellbore geometry drive everything. A vertical well to 2,500m MD costs fundamentally differently than a 45° deviated well to the same TVD.
Step 2 - Build the Casing Program
Each casing string has associated costs: tubular cost ($/ft or $/m), cementing volume, and running time. Example:
| Casing String | Size | Depth (m) | Est. Cost (USD) |
|---|---|---|---|
| Conductor | 30" | 60 | $45,000 |
| Surface Casing | 13⅜" | 500 | $280,000 |
| Intermediate | 9⅝" | 1,800 | $620,000 |
| Production Liner | 7" | 2,800 | $390,000 |
Step 3 - Estimate Drilling Days (the critical number)
Most costs are time-driven. The formula is simple:
Total Drilling Cost = Rig Day Rate x Planned Days + Fixed Costs + Contingency
Example calculation:
- Rig day rate: $45,000/day
- Planned drilling days: 28 days
- Fixed costs (casing, logging, cementing): $1,200,000
- Contingency (12%): $271,200
- Total AFE: $2,731,200
Step 4 - Apply the Non-Productive Time (NPT) Factor
Industry average NPT is 8-15% of planned time on land rigs, and up to 20% on deepwater operations. Always build this into your planning days, not your contingency.
Real-World Lesson: The 10% Savings That Changed the Project
On a West African deepwater exploration project, our team faced $12M in projected costs for a single exploratory well. The original plan used a premium semi-submersible rig at $320,000/day.
By optimizing the casing program (eliminating an intermediate string through better pore pressure prediction), we reduced planned days from 38 to 31 - saving 7 rig days at $320,000/day = $2.24M saved, nearly 19% of the original budget.
The lesson: the best place to save money in a well is the planning phase, not during execution. Every engineering decision made on paper is 100x cheaper than a modification made downhole.
Key Performance Indicators for Well Cost Control
Track these KPIs on every well you manage:
- Cost per meter drilled ($/m) - benchmark against offset wells
- AFE vs Actual variance (%) - target <5% overrun
- NPT percentage - track causes (stuck pipe, weather, equipment)
- Flat time vs rotating time ratio - identifies operational inefficiencies
- Invisible Lost Time (ILT) - time lost without being logged as NPT
Conclusion
Well costing is one of the highest-leverage skills in petroleum engineering. A 5% improvement in cost estimation accuracy on a $5M well saves $250,000 - that's real money that impacts project viability and company profitability.
Master the AFE structure, understand what drives rig time, and always plan for NPT and contingency before you spud. That discipline separates good drilling engineers from great ones.
Have questions about well cost estimation or AFE structure? Leave a comment below or join our Telegram group to discuss with other petroleum professionals.
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