How to Identify Wells Past Their Cumulative Production Projection
For Australian analysts tracking US shale assets from a desk in Perth or Brisbane, recognising when a horizontal well has crossed below its type-curve forecast matters well beyond curiosity. It shapes mineral-rights valuations, divestment timing, and the credibility of reserve reports that feed half-yearly portfolio reviews. Wells that quietly slip behind their cumulative production projection can erode the economics of an entire pad before anyone notices in the monthly operating report.
The term refers to the running total of gas and liquids a well is expected to have produced by a given month, usually built from a decline-curve model calibrated in the first six to twelve months of flowback. Once a well falls under that line and stays there, the operator, royalty owner, and engineering team each have a stake in knowing. For someone working across time zones from Sydney to Houston, fast access to the right data layers can compress a three-week investigation into a thirty-minute query.
Shale Navigator was built to compress that workflow into a map-driven exercise. By layering producing wells against completion reports, vintage data, and analogue offsets, the platform lets you spot laggards without manually stitching together state agency files. What follows walks through how to interpret the projection, where to look on the platform, and how to keep watch over time.
What the projection actually measures
A cumulative production projection is a forward-looking curve drawn from early flowback data, reservoir properties, and analogue behaviour. Most operators publish a P50 case alongside low and high scenarios, but the central tendency is enough for screening. The model assumes a hyperbolic decline, bores through the steep flush production of the first ninety days, and smooths into the long tail where most of the economics are made. Anything that disrupts the assumed flow path — a frac hit, a costly workover, or a casing breach — pulls the cumulative line below the projection.
The moment a well falls below its expected curve matters because unconventional economics are built on aggregate pad performance rather than single-well outcomes. A few wells running fifteen percent behind the type curve can absorb capital that should have funded the next section. For Australian investors with US shale exposure through their super allocations or directly through listed juniors, this distinction shows up in dividend coverage of midstream partners and eventual impairment decisions of the operator.
Reading the gap correctly requires a baseline. State agencies like the Texas Railroad Commission publish monthly volumes by API number, but the projection itself is rarely public. Shale Navigator joins completion reports, first-month production, and vintage curves into a single layer that can be queried by section, township, or operator, removing the need to reconstruct the projection manually.
Recognising the crossover on a decline curve
The crossover is the point where actual cumulative production crosses beneath the projection and refuses to climb back. It is rarely a single month of bad numbers; it is a sustained drift that becomes statistically obvious after four to six consecutive reporting periods. Engineers call this the well going off-trend, and from a financial reporting standpoint it is the threshold that triggers a reserve revision.
To spot it, plot monthly production against the projection for each candidate well and look for three patterns. A flatter initial decline than the type curve assumed usually means the well never achieved the modelled connection to the rock. A sharper drop in months seven through eighteen often signals proppant flowback, water loading, or a casing issue. A flat tail can indicate depleted drainage area or interference from parent-child spacing.
Australian engineers who have worked the Beetaloo pilots in the Northern Territory will recognise these signatures from local tight gas experience. The Cooper Basin tight sand plays and the Velkerri shales share analogue behaviour with the US Marcellus and Eagle Ford, which is why the same diagnostic instincts apply when reviewing a Haynesville or Barnett package from an office in Adelaide or Melbourne. The vocabulary travels with the reservoir, even when the field names do not.
Using Shale Navigator layers to find the laggards
The platform exposes a producing wells layer that can be filtered by vintage, formation, operator, and county. Layering that on top of completion reports means the matching is automatic. From there, compute the difference between reported monthly volumes and the projected cumulative figure for each well, then colour-code the map by the gap.
The Activity Feed keeps watch on permit and lease changes that may have coincided with the production slip, helping separate operational issues from geological ones. A well that fell off curve the same month a competitor's well was completed one spacing unit away tells a different story to one that quietly declined while nothing changed around it. For Australian users on AEST, overnight US filings appear in the morning queue, ready for review before the local trading day starts. The guide on using the activity feed walks through the relevant filters.
Beyond activity, the parcel and mineral rights layers let you estimate the revenue impact of a lagging well on the royalty stream for any section. Drawing a polygon around a pad and joining the production deficit to underlying lease terms translates an engineering observation into a dollar figure that holds up in a partner meeting or an APPEA roadshow.
Comparing against analogue offsets
No well operates in a vacuum, and a single underperformer can reflect either a localised problem or a basin-wide shift. The diagnostic move is to compare the candidate well against its nearest analogues — same formation, similar lateral length, similar stage spacing, completed within the same eighteen-month window. If neighbours track their projections and the candidate does not, the issue is likely well-specific. If neighbours are all drifting together, the issue is likely reservoir, market, or operator-wide.
Shale Navigator makes this comparison straightforward through its offset well tool, which automatically identifies the closest producing wells by latitude, longitude, and target formation. The map can be re-styled to show production index, where values above one indicate the well is ahead of the basin average and values below one indicate it is lagging. A cluster of sub-one wells in the same county, on the same formation, completed in the same year is rarely coincidence and warrants deeper investigation.
For an Australian analyst used to the homogeneity of Cooper Basin fields, US shale heterogeneity can be a surprise. The Marcellus varies block by block across Pennsylvania and West Virginia, and the Permian varies by bench within the same pad. Offset comparisons are not just a sanity check; they are the primary tool for separating a real underperformer from a statistical outlier in a noisy dataset.
Practical workflow for tagging and tracking
Run these steps in order to build a watchlist that updates with each new monthly production report.
- Pull the producing wells layer for the county or play of interest and filter to wells older than eighteen months, so the early-production noise has settled.
- Overlay completion reports and select wells with similar lateral length, proppant intensity, and stage count to build a fair peer group.
- Compute the production index by dividing reported cumulative production by the projected cumulative figure, then flag wells below 0.85 as candidates for closer review.
- Cross-check the flagged wells with the Activity Feed to see whether any permit, lease, or regulatory events coincided with the production drop.
- Re-run the analysis quarterly, because wells that are merely slow in year one can catch up, and wells on-trend in year one can fall off in year three once parent-child interference accumulates.
These steps are the same workflow used by US-focused engineering teams now applying their methods to the Velkerri and Kyalla shales emerging from the Beetaloo. Australian juniors listed on the ASX who hold US acreage can run the analysis internally once data is structured, but most choose to subscribe to a platform that has already done the layering work. A free seven-day account lets you test the workflow on a real dataset before committing to a paid subscription.
For anyone with skin in the US shale game — whether the asset sits in a Perth investment portfolio, a Brisbane superannuation mandate, or a Sydney advisory practice — staying ahead of the projection is non-negotiable. Map your wells of interest today, run the production index against the projection, and watch the Activity Feed for filings that change the picture overnight. Wells that slip behind their cumulative production projection rarely announce themselves in headlines; they reveal themselves in the data, and the data is at your fingertips.