Exploration & Production Models
Executive Summary
Key Takeaways
- ✓ Exploration and production models are built at the well and pad level, using type curves, a rig-count-driven drilling schedule, and per-well capital and operating cost, distinct from the segment-wide reserve and fiscal mechanics covered in Upstream Financial Models.
- ✓ A type curve represents the expected production decline profile of a representative well in a given area, and is the basic building block from which a multi-well development's aggregate production is constructed.
- ✓ The drilling schedule, how many wells are drilled per period given a fixed rig count, directly determines the pace of production ramp-up and capital deployment, and should be modelled explicitly rather than assumed as a smooth annual programme.
- ✓ Per-well capital cost assumptions should reflect the specific well design, lateral length, completion intensity, rather than a single blended average cost applied to every well regardless of design.
- ✓ Aggregate field production in an E&P model is the sum of overlapping individual well type curves at different points in their own decline, not a single field-level decline curve applied directly to total volume.
Objective¶
This guide sets out how exploration and production (E&P) asset models are built at the well and pad level, complementing the segment-wide economics covered in Upstream Financial Models, within Oil & Gas Financial Modelling.
Type Curves as the Basic Building Block¶
A type curve represents the expected production decline profile of a representative well in a given area, built from the observed or forecast performance of comparable wells. A multi-well development's aggregate production is constructed as the sum of individual well type curves, each starting its own decline from the point it is drilled and brought online, not as a single field-level decline curve applied directly to total volume.
Drilling Schedule and Rig Constraints¶
The pace at which new wells are added is constrained by the number of rigs actively drilling, and the resulting drilling schedule directly determines both the pace of production ramp-up and the pace of capital deployment. Modelling the drilling schedule explicitly, rather than assuming a smooth, unconstrained annual drilling programme, is necessary to represent realistic production ramp-up timing and capital phasing.
Per-Well Cost Assumptions¶
Per-well capital cost should reflect the specific well design actually planned, lateral length, completion intensity (number of frac stages, proppant volume), and location, rather than a single blended average applied uniformly across every well. Where a development programme includes wells of varying design, the model should carry cost assumptions specific to each well category to test the programme's actual cost sensitivity.
Building Aggregate Production From Well-Level Detail¶
Because each well is at a different point in its own decline depending on when it was drilled, aggregate field production in an E&P model is the sum of these overlapping, offset well-level curves, a materially different construction from applying one field-level decline directly to total historical volume. This well-level approach is what allows the model to represent the effect of an ongoing drilling programme, adding new, high-rate wells even as older wells continue to decline, on total field output.
Common Structuring Pitfalls¶
- Applying a single field-level decline curve to aggregate production rather than summing individual, appropriately offset well-level type curves.
- Assuming an unconstrained drilling schedule that ignores the actual number of rigs available to the programme.
- Using a single blended average per-well cost across wells with materially different designs.
- Failing to update type curve assumptions as actual well performance data becomes available from wells already drilled in the programme.
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Frequently Asked Questions
How does an exploration and production model differ from a segment-level upstream model?
An E&P model is built at the well and pad level, using type curves, drilling schedules and per-well cost assumptions, while a segment-level upstream model, addressed in Upstream Financial Models, focuses on the aggregate reserve base, fiscal terms and reserve-based lending mechanics. The two are complementary levels of detail.
What is a type curve?
A representative production decline profile for a well in a given area, built from the observed or forecast performance of comparable wells, and used as the basic building block for constructing a multi-well development's aggregate production forecast.
How does the drilling schedule affect the model?
The number of wells drilled per period, constrained by the number of rigs actively drilling, determines the pace at which new wells are added and therefore the pace of production ramp-up and capital deployment, and should be modelled explicitly rather than assumed as a smooth, unconstrained annual programme.
Why shouldn't per-well capital cost be a single blended average?
Because well design, lateral length, completion intensity, and location, materially affect actual cost, and a single blended average obscures the cost sensitivity a development plan should be tested against when well designs vary across the programme.
How is aggregate field production actually built up in an E&P model?
As the sum of multiple individual well type curves, each at a different point in its own decline depending on when it was drilled, rather than a single field-level decline curve applied directly to total volume, which would misrepresent the effect of ongoing drilling activity on aggregate output.
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