Stretching Returns: A Comparative Look at Extended Laterals

Benchmarking performance of 3-mile laterals using the AFE Leaks Well Cost Database

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Let’s take a closer look at where capital efficiency peaks — and where it breaks.

Background

In theory, longer laterals should deliver better returns: fewer surface locations, bigger frac jobs, and more barrels per well. But what happens when you stretch too far?

At AFE Leaks, we’re not working off assumptions. We benchmark performance using real, component-level capex and production data across 95,000+ Lower 48 wells. That means we don’t just know what operators planned to spend — we know what they actually did.

In this deep dive, we analyze 3-mile laterals using real AFE and Actuals, pairing them with offset well production to evaluate whether the returns scale or stall. The result: a play-by-play breakdown of costs, productivity, and efficiency inflection points.

Our goal is to isolate the capital and productivity impact of extended laterals, controlling for geology and operator design.

This analysis combines spatial well matching, detailed cost benchmarking, and productivity comparisons across thousands of horizontal wells drilled since 2020. All data is drawn from the AFE Leaks cost and production database, integrating public filings, survey shapefiles, and proprietary normalization logic. Here’s how the analysis was conducted:

Well Matching & Filtering

We began by identifying wells with perforated intervals greater than 14,000 feet across major U.S. plays. To build meaningful comparisons, we used spatial joins and buffer logic (typically 3–5 mile radii) to find offset wells in the same reservoir and with similar spud timing (within ±12 months). Numerous reservoir-specific anti-joins were applied to prevent mismatches (e.g., excluding Wolfcamp A–D mismatches).

Capex Benchmarking

Wells were paired such that a longer-lateral “parent” well was compared to a nearby (< 5 miles away) shorter “child” well. AFE and Actual costs were aggregated from component-level data (cost_breakdown_details) and grouped by Drilling, Completion, and Pre-Drill categories. These were rolled up to calculate capex per well by lateral length bin:

1-mile (4,000–6,000 ft)

1.5-mile (6,000–8,500 ft)

2-mile (8,500–11,000 ft)

2.5-mile (11,000–14,000 ft)

3-mile (14,000–16,500 ft)

Cost ratios (child/parent) were calculated and plotted, at the well-level and then as play-level medians.

Production Matching

Using survey shapefiles and spatial joins, we applied the same matching logic to find offset wells for productivity comparisons, though restricted offset distance to < 3 miles. Wells were included only if they had at least 26 months of valid non-zero production history. For each well, we computed cumulative 24-month BOE, applying a 20:1 gas-to-oil ratio, and compared these to their offset counterparts to generate a normalized productivity uplift ratio.

Statistical Fitting & Visualization

Cost and productivity uplift percentages were plotted against perf length. A 2nd-order polynomial regression was fit to the productivity data and a linear model to cost increases. These allow for a smoothed view of the structural trends and where diminishing returns appear to set in.

Optional Breakout by Capex Phase

For a deeper dive, we aggregated cost differences by AFE phase (Drilling, Completion, Pre-Drill) and by further sub-category to look at which cost categories were most impacted by lateral extension — highlighting areas such as Casing, Stimulation, and Rig Time as primary cost drivers.

Cost Escalation: Predictable, Until It Isn’t

We start with the cost side. Using paired well analysis within a 5-mile radius, we compare 3-mile laterals against 1-, 1.5-, 2-, and 2.5-mile offsets. Importantly, these comparisons are all made within the same reservoir and under the same operator, helping control for design and operational variance.