Wellbore Stage Visualization with Cost Analysis

Drag to rotate · scroll to zoom · right-drag to pan. Adjust parameters on the left, cost inputs on the right.

How to read this

Two parallel laterals contacting the same reservoir. Both wells are the same total length — the only difference is how stages are spaced.

01

Geometric well

Every stage is the same length, toe to heel. Industry default. Predictable to pump, but assumes every part of the reservoir responds the same way — which it doesn’t.

02

Variable well

Stages lengthen from toe to heel. Same total lateral, fewer stages overall. Bars above each stage scale with stage length so you can see the geometry at a glance.

03

Economics panel

Live AFE math. Wireline + plugs avoided, frac time saved, fluid totals. Drop in your own cost inputs to see what variable staging is worth on your wells.

What it shows

Variable staging takes real money off the well. A 40-stage well dropping to 32 stages avoids 8 wireline runs and 8 plugs — six figures per well at typical service costs, before any frac-time savings.
The savings scale with stage count. Push the stage-count slider up. Long laterals with high stage counts are where variable design pays the most.
The increment is the lever. Larger increments mean fewer, longer stages and bigger savings — but more demand on every cluster to actually take fluid. Past a point, you’re trading completion cost for production risk.
Variable staging only pays off if clusters actually contribute. A longer stage with more clusters only works if all of them break down and take rate. If half stay dead, you saved a plug and lost reservoir contact.

Why this matters for closed-loop fracturing

The cost case for variable staging is obvious. The reason most operators don’t push it harder is that they can’t see what happens at the cluster level — so they default to the conservative geometric design and leave dollars on the location.

THE GAP

Surface pressure isn’t enough

Treating pressure tells you the well is taking fluid. It doesn’t tell you which clusters — or whether the variable design you pumped is delivering uniform contribution stage by stage.

WHAT SAFA DOES

Measure cluster contribution in real time

SAFA™ uses surface acoustics to measure perforation efficiency and uniformity index intra-stage — no downhole tools. You see whether the longer stages in your variable design actually work, while you’re still pumping.

THE LOOP

Adapt the next stage

When measurement closes the loop, you can pump variable designs aggressively because you’ll catch under-contributing stages on the next one — not on the production curve six months later.

About this model. Cost figures are illustrative and based on the inputs you set. Frac time uses a simple linear-fluid model and assumes a ramp to max rate; actual time per stage depends on fluid schedule, formation breakdown, and rate management. Variable-length staging requires real-time cluster-level diagnostics to be safely pumped at scale — without measurement, longer stages carry a corresponding production risk that this tool does not model. SAFA™ is the acoustic-measurement layer that makes variable, closed-loop completions design defensible at the wellhead.

See how SAFA measures cluster contribution in real time

Variable staging on the design side. Acoustic cluster-level measurement on the execution side. That’s the closed loop.

Explore SAFA Technology Closed-Loop Fracturing