The setup
A mid-size conventional operator holding an onshore license in the Sub-Andean foredeep of South America was preparing to commit to a 2D and partial 3D seismic program across its entire 180 km² block. The lease was in a frontier zone with modest legacy well coverage — enough regional geology to justify the block, but not enough to rank prospects within it. The planned seismic budget was in the low eight figures USD, with acquisition and processing expected to take 10–14 months.
Before committing the seismic capital, the operator engaged Inside Earth to screen the block for hydrocarbon presence and identify the sub-areas most likely to justify full 3D coverage. The scope was deliberately framed as "should we even do the seismic we're planning?"
The approach
We ran our standard remote NMR subsurface mapping workflow across the full lease outline — multi-spectral satellite acquisition, pre-processing, signature classification against our calibrated library, NMR-based substance interpretation, and calibration against the small number of legacy wells in the region. Target depth range was 2,500–8,500 feet based on the operator's regional play model.
Delivery window was compressed: the operator's investment committee met five weeks after NDA signing, and the result needed to be in their hands for that meeting.
The result
The screening returned four hydrocarbon-confirmed target polygons — collectively covering roughly 35% of the lease area — with per-polygon confidence scores and depth-to-top-of-reservoir estimates. Two of the four overlapped with the operator's a priori ranked targets; two were surprises, including one in an area the regional play model had graded as secondary.
Critically, 65% of the lease area returned no hydrocarbon signature. The operator's investment committee used this result to:
- Cut the planned seismic program to cover only the four confirmed polygons and their surrounds — reducing scope by 2.6× and cost by an estimated $4.2M.
- Re-sequence the drilling plan to prioritize the two surprise targets that had previously been ranked secondary.
- Defer any acquisition in the unconfirmed 65% of the block pending further interpretation.
What happened next
The reduced seismic program was acquired over the following 11 months. The first exploration well was drilled 15 months after the remote survey was delivered. At time of writing (Q1 2026), three wells have been drilled across the confirmed polygons, with outcomes consistent with the pre-drill indications. Drilling continues.
What this case illustrates
This engagement is a clean example of the "screen, then focus" pattern described in NMR vs seismic. Remote NMR didn't replace seismic — it shaped what seismic was going to be acquired, and where. The commercial leverage is asymmetric: spending low-to-mid six figures on remote mapping saved low seven figures on a seismic program that would have been acquired blind.
The result also illustrates a less-advertised benefit: remote screening sometimes surfaces prospects the conventional workflow misses. Two of the four confirmed polygons were outside the operator's pre-screen ranked list. Without the screen, those prospects would have been deprioritized in the 3D acquisition design and potentially never drilled.
Identifying details
This case study is based on a real Inside Earth engagement. Basin, operator identity, exact lease geometry, and financial details have been anonymized per NDA. Order-of-magnitude numbers reflect the engagement; exact figures vary within the stated ranges.