FastFrac Input Guide

What every entry means, where the number comes from, and what to do when you do not have it

Aegis Solutions Group, LLC | FastFrac | fastfrac.net

Revised 20 October 2026

What this guide is. A field-by-field reference for the design inputs. For each entry it says what the quantity is, where an engineer normally gets it, what to do when it is not available, and which part of the answer it moves.

What it is not. It is not the Model basis page inside the software. That page carries every equation the engine applies with its published source, and it is the right place to look when you want to know how a number was calculated rather than what to type.

A note on defaults. Every field opens with a value. Those values are there so a new design runs rather than sitting empty, and they are not recommendations. Replace them with your own well data before you believe anything the run tells you.

1 Design identification

Three text fields. They do not affect the calculation; they make a printout traceable.

Well ID

Text.

The name the design is saved and printed under. It appears at the top of every printed page and becomes the suggested file name when you save the design to your computer. Use the operator's own well name so a printout found on a desk six months later can still be tied to a well.

Prepared by - Company

Text.

Both print on the report header. The printed report is an external document: it is written to be handed to a partner, a service company or a manager, so fill these in rather than leaving the placeholder names on a document that leaves your desk.

2 Well and completion data

The pipe the fluid travels through. These set friction, wellbore volume, displacement and the pressure limit, not the fracture itself.

Well type

Vertical or Horizontal. Default Vertical.

Choosing Horizontal reveals two further fields, true vertical depth and liner ID. The distinction matters because the two things depth controls pull apart on a deviated well: pressure depends on how far down you are, friction depends on how far along the pipe the fluid has travelled. On a vertical well the two are the same number and the extra fields stay hidden.

Measured depth

ft. 500 to 25,000.

The length of pipe the fluid travels to reach the stage being treated. It sets the pipe friction, the wellbore volume and therefore the displacement.

From the completion record. On a horizontal well this is the measured depth to the stage you are treating, not to the toe of the lateral, unless the toe is the stage.

True vertical depth

ft. Horizontal wells only. 0 uses the measured depth.

The height of the fluid column. It sets the hydrostatic head, the fracture pressure and the reservoir pressure, because all three act over vertical height.

From the directional survey. Leave it at 0 on a vertical well. If you enter a true vertical depth greater than the measured depth the model tells you so and uses the measured depth for both, since that combination is not physical.

Liner ID

in. Horizontal wells only.

The inside diameter the fluid flows through along the lateral, for friction and volume. Where the lateral is cased with the same string that runs to surface, this is simply the casing ID and can be left matching it.

Casing ID - Casing OD - Casing weight - Casing grade

in, in, lb/ft, and a grade from H-40 to Q-125.

Take all four from the casing tally or a pipe table, and take them from the same row of that table. They must describe one real pipe.

The software checks them against each other. A dashed border around these fields means the combination you have entered does not describe a pipe that exists, which usually means one of the four was copied from a different row.

Casing burst rating

psig. Computed, not entered.

API 5C3 internal yield, worked out from the casing OD, weight and grade above. You cannot type over it. To change the rating, change the pipe.

The results page compares your peak surface pressure against this figure and flags the stage that exceeds it.

Annulus back pressure

psi. Default 0.

Pressure held on the annulus during the treatment to reduce the differential the casing has to stand. It enters the burst check only, and nothing else in the calculation.

Enter the pressure being held. If none is held, leave it at 0.

Fracturing path

Down casing, down tubing, or down the tubing-casing annulus.

Which bore carries the treatment. It decides the flow area used for friction and the capacity used for the wellbore volume and the displacement, so it changes surface pressure substantially. The annulus path is the one most often got wrong: it is the space between the tubing OD and the casing ID, not either pipe on its own.

Tubing depth - Tubing ID - Tubing OD

ft, in, in. Shown only when the path uses tubing.

The tubing string in the hole. Where the tubing stops short of the perforations the model carries the remaining distance in the casing, so the depth matters as much as the diameters.

Number of parallel fractures

count. 1 to 20. Default 1.

How many fractures take fluid at the same time: clusters in a stage, or separate perforated intervals. This primary count sets the total number of perforations. At zero complexity adjustment, injection rate is divided equally between these fractures.

Folds of increase assumes a single fracture draining a circle and is not reported when the effective parallel-fracture count exceeds one.

Fracture complexity adjustment

%. Nonnegative. Default 0%.

Represents additional complexity through an assumed increase in equivalent parallel fractures. Effective count = primary count x (1 + adjustment / 100). Eight primary fractures with a 10% adjustment become 8.8 equivalent fractures.

Rate, volume and proppant are divided by the effective count in the fracture calculations. Geometry, leakoff, placement and conductivity are recalculated. Physical clusters and perforations are unchanged.

Use 0% unless exploring a sensitivity or documenting a calibrated assumption. Zero applies no adjustment; it does not establish that actual fractures are unbranched. There is no prescribed percentage for a shale play. Microseismic extent alone does not determine it. Record the basis for a nonzero value; do not choose it solely to obtain a preferred half-length.

This is a FastFrac modeling assumption, not a published branching or fracture-swarm correlation. It does not resolve branching geometry, stress interaction or unequal fluid and sand distribution. A 10% adjustment does not mean 10% more area, 10% less length or 10% more production.

Effective parallel fractures

count. Calculated.

Primary count multiplied by (1 + complexity adjustment / 100). Fractional values are equivalent counts, not literal partial fractures. This value is included in the report.

Perforations per primary fracture - Perforation diameter

count and in. Default 12 holes at 0.59 in.

The holes feeding one fracture, used for the perforation pressure drop. Count the holes feeding a single fracture, not the whole stage: the model multiplies by the number of primary parallel fractures itself. The complexity adjustment does not change this count or the perforation-friction calculation.

Use the shot density and the interval open. The discharge coefficient is built into the calculation and is not something you enter.

3 Reservoir data

What the rock does with the fluid you lose to it, and the basis for the productivity comparison.

Net pay thickness

ft. 1 to 1,000.

This is the single most misread entry in the program. It is the permeable thickness that takes fluid. It is not the fracture height.

Fluid is only lost where the face of the fracture stands against permeable rock. The model therefore caps the leakoff area by this thickness: a fracture that grows well out of zone leaks only over the pay band through its middle and not over its whole face. Entering a fracture height here instead will make the job look far leakier than it is.

From logs, using your usual porosity and permeability cutoffs. Where the fracture is contained inside the pay, the two numbers are close and the distinction does not bite. Where it is not, this entry changes the answer more than almost anything else.

Average permeability

md. 0.00001 to 100,000.

Enters both leakoff terms and the dimensionless conductivity. In a tight rock it is the number the whole fluid-loss calculation turns on.

From core, from a log-derived permeability transform, or from a well test. Shales run in the hundreds of nanodarcies, so values like 0.0004 md are ordinary here and the field accepts them.

Average porosity

fraction. 0.01 to 0.5.

The reservoir rock porosity, not the proppant pack porosity, which is a separate entry further down. It enters both leakoff terms. From logs.

Reservoir fluid viscosity

cp.

The viscosity of the fluid already in the pores, which has to be pushed aside by the filtrate invading the rock. It enters the reservoir-controlled part of the leakoff only.

If you do not have it, the Toolbox will estimate it for oil, gas or water from gravity, temperature and pressure, and write the answer straight into this field.

Total compressibility

x10^-6 psi^-1.

The total system compressibility, reservoir fluid plus pore volume. It governs how readily the fluid in the rock can be compressed to make room for what is leaking in, so it sets the reservoir-controlled leakoff with the viscosity above.

A gas reservoir is highly compressible and offers little resistance; an oil or water system is stiff and offers a great deal. The Toolbox will estimate it if you do not have a measured value.

Reservoir pressure gradient

psi/ft. 0.1 to 1.2.

The pore pressure gradient. With the fracture gradient it fixes the differential pressure that drives fluid into the rock, so it drives the leakoff and the fluid efficiency.

From a pressure survey, a DFIT, or offset data. It must be less than the fracture gradient. If it is not, there is no differential to drive leakoff and the model will say so rather than return an answer.

Reservoir temperature

degF. 32 to 400.

The fracture calculation does not read this field. Changing it will not move any result on the fracture pages. It is carried so the printed record is complete, and it seeds the Toolbox.

How that seeding works. The first time you open the Toolbox on a design, this temperature is copied into the Toolbox's own temperature field, along with the porosity and a reservoir pressure worked out from the depth and the pressure gradient. After that the Toolbox keeps its own values. Editing the reservoir temperature here later does not flow back into a Toolbox you have already opened; change it in the Toolbox as well if that is what you meant.

Drainage area - Drilled hole diameter - Skin, unfractured

acres, in., and a dimensionless skin. Defaults 160 acres, 8.75 in., skin 0.

These three are used by one figure only, the folds of increase, which compares the fractured well against the same well unfractured over the same drainage area. Nothing else on the results page depends on them.

The drainage area sets the drainage radius. The hole diameter is the bit size and is halved to give the wellbore radius. The skin is the damage on the unfractured well that the fracture bypasses: positive is damage, and leaving it at 0 compares against an undamaged well.

4 Rock mechanical properties

Four entries, and one of them is the largest single assumption in the model.

Young's modulus

x10^6 psi. 0.1 to 12.

The stiffness of the rock. With Poisson's ratio it forms the plane strain modulus, which sets the fracture width. A stiffer rock gives a narrower, longer fracture for the same job; a soft rock gives a wide, short one.

Properly from core, measured statically. More often from sonic and density logs, which give a dynamic modulus that is then correlated to a static value. If you have neither, the Toolbox will give you an estimate to work with.

Poisson's ratio

fraction. 0.1 to 0.49.

Enters only through the plane strain modulus, and over its usual range it moves the answer far less than Young's modulus does. Same sources: core, or sonic and density logs. If it is unknown, an area-typical value will not hurt you much.

Fracture gradient

psi/ft. 0.1 to 1.5.

The closure stress gradient, which the model also uses as the treating pressure in the fracture. It sets the bottomhole pressure the pumps have to reach and, with the reservoir pressure gradient, the differential that drives leakoff.

The direct measurement is a diagnostic fracture injection test or a minifrac on the well itself. Failing that, an area value or an offset. It is worth getting right: it moves both the surface pressure and the fluid loss.

Containment height

ft. 0 means radial. Default 0.

Enter 0 and the model grows a radial fracture, a penny spreading out from the perforations with nothing to stop it. Enter a height and the fracture is confined to that height and grows in length only.

Use 0 where there is no real barrier, or where the pay is thick enough that the fracture is free to grow in every direction for most of the job. Use a height where logs show a genuine stress contrast above and below the zone that will hold the fracture in.

Where does the number come from? A stress profile built from sonic and density logs, calibrated where possible against a DFIT, and read for the stress contrast between the pay and the bounding beds. A few hundred psi of contrast is a weak barrier; something approaching a thousand is a strong one. Offset treatment records and any height measurement you have, from tracers, temperature logs or microseismic, are worth more than any correlation.

This entry drives the fracture area, the width and the area available to leak off, so it moves the whole answer. The model takes it from you rather than computing it. If you are unsure, run the design both ways and see how much of your conclusion survives.

5 Fracturing fluid properties

One Newtonian viscosity, by design. The model does not carry a power-law fluid.

Fluid viscosity

cp. 0.1 to 2,000.

The viscosity of the treating fluid as pumped. It does three jobs at once: it sets the fracture width, the friction down the pipe, and the viscosity-controlled part of the leakoff.

From the service company's fluid data at the reservoir temperature and the shear rate you expect, or from the Toolbox. Slickwater is a few centipoise, a linear gel is usually in the tens, a crosslinked gel in the hundreds.

The model thickens this value with the sand it is carrying when it works out the fracture width, so you enter the clean fluid viscosity here and the program takes care of the rest.

Friction reduction

%. 0 to 99. Default 0.

Turbulent drag reduction from a friction reducer, applied to the pipe friction and nothing else. It does not touch the fracture.

Take it from a step-down test on the well, from an offset, or from the service company's own figures for the loading you are running. Leave it at 0 for an untreated fluid. A high value here lowers the computed surface pressure.

Fluid specific gravity

SG. 0.5 to 1.5. Default 1.05.

Sets the hydrostatic head, which you get back as a credit against the surface pressure, and enters the friction. Water is 1.0; a gelled and weighted fluid is a little above it.

6 Proppant properties

What holds the fracture open, and how well it will flow afterwards.

Proppant mesh size

8-12 through 100 mesh. Default 20-40.

The sieve cut. The model uses two different grain sizes from it. The coarse sieve opening sets the bridging check, because bridging is decided by the biggest grains in the batch. The median grain sets the pack permeability and the settling calculation, because those are properties of the bulk.

A coarser cut flows better but needs a wider fracture to enter: pack permeability rises with the square of grain size, and so does the width you need to avoid bridging.

Proppant specific gravity

SG. 1 to 4. Default 2.65.

Sand is 2.65 and that covers most jobs. Lightweight ceramics sit near 2.7, intermediate strength above 3.0, high strength above 3.3, and ultralightweight products come down near 2.0. From the supplier's data sheet.

It enters the slurry volume, the settled pack volume and the settling velocity.

Proppant pack porosity

fraction. 0.2 to 0.5. Default 0.37.

The void fraction of the settled pack. It sets how thick a pack a given weight of sand makes, and it sets the pack permeability very strongly, since permeability goes as the cube of porosity.

It is not a property of the mesh size. A sieved pack has much the same void fraction whatever the grain diameter; what moves it is how broad the cut is, the grain shape, and what happens under closure stress. Published values for sand are 0.35 to 0.40 unstressed.

Suppliers publish bulk density rather than porosity. To convert: porosity is 1 minus the bulk density divided by 62.4 times the proppant specific gravity. A bulk density of 100 lb/ft^3 for 2.65 sand is a porosity of about 0.40.

Conductivity damage factor

fraction. 0.05 to 1. Default 1.0.

A straight discount on the clean pack conductivity, covering everything the model does not calculate: crushing, embedment into soft rock, unbroken gel residue in the pack, and multiphase flow through it.

The default of 1.0 is the clean, undamaged pack, so no damage is assumed unless you enter it. Values of 0.1 to 0.5 are common in practice. If you have retained conductivity data for your fluid and proppant, use it.

7 Treatment design and the pump schedule

The rate, and the stage-by-stage schedule that is the heart of the design.

Injection rate

bbl/min. 1 to 150. Default 20.

Slurry rate at surface, totalled across every fracture taking fluid. The model divides it by the effective number of parallel fractures, including any complexity adjustment, to get the rate into each equivalent fracture.

It is the most powerful single lever you have. It raises the width, shortens the time the fluid has to leak off, and raises the surface pressure and the horsepower bill all at once. It is held constant for the whole job, which is what the leakoff solution assumes.

Displacement volume

bbl. Computed, not entered.

The capacity of the wellbore along the flow path you selected, worked out from the depth and the tubulars. It is shown so you can carry it into the schedule as the final stage.

If you change the flow path or any pipe dimension, this figure changes with it, and the displacement stage in your schedule should be brought back into line.

The pump schedule

One row per stage.

Each row carries a label, a slurry volume in barrels, a proppant concentration, and a flag marking the displacement.

Concentration is pounds of proppant added per gallon of clean fluid, the usual field convention, not pounds per gallon of finished slurry. The program works out the extra volume the sand occupies for you.

Rows carrying no proppant before the first sand stage are the pad. Their job is to open enough fracture that the first sand has somewhere to go. The results page compares your pad against the published rule and tells you whether the job is under-padded, over-padded, or about right.

The last row is normally the displacement, with its flag set. Flagged that way the fluid stays in the wellbore, places no proppant, and still counts for time, pressure and horsepower.

8 The Toolbox

For the entries you do not have measured.

The Toolbox estimates reservoir and fluid properties from things you are more likely to know: oil gravity, gas gravity, temperature, pressure and salinity. It covers oil, gas and water properties, the total system compressibility, and rock mechanical properties.

Each result carries a Use in design button that writes the value straight into the matching input field, so there is no transcription to get wrong. The Toolbox has its own basis page listing the correlations it uses and where they come from.

Generic clean gel. Enter fluid temperature from 60 to 180 F and gel loading from 0 to 80 lb per 1,000 gallons of water. Zero loading uses IAPWS SR6-08(2011) pure-water viscosity at 0.1 MPa. Below 10 lb, the result is linearly interpolated between water and the extrapolated 10 lb gel estimate. At 10 to 80 lb, it averages three chart estimates from the author's engineering files. Use in design fills treating-fluid viscosity. These are clean-fluid estimates; they do not predict the viscosity of an added friction reducer. The Toolbox Basis gives the equations, assumptions and source link.

It seeds itself from the design once. The first time you open the Toolbox on a design it takes the reservoir temperature and porosity from your inputs, and works out a reservoir pressure from the depth and the pressure gradient. From then on it keeps its own values and is restored from them. If you later change one of those three on the design pages, change it in the Toolbox too, because it will not follow.

Use it to get moving, and replace its estimates with measured data when you have it. A correlation is a reasonable starting point and nothing more.

9 Before you trust a run

A short list worth working through on any design you intend to act on.

Is net pay the permeable thickness, and not the fracture height? This is the most common mistake and it changes the fluid efficiency dramatically.

Does the containment height reflect a real stress barrier? If it was a guess, run the design at 0 as well and see whether your conclusion survives being wrong about it.

Look at the four placement flags on the results pages. A proppant fill reaching 100 per cent, a stage resting on its own settled pack in the In fracture column, a width over grain below three, and a settling figure above 100 per cent. Each is coloured where it trips, each carries its own explanation on hover, and together they are the model telling you the job is in trouble.

Check the pad fraction against the rule. Under-padded is the dangerous direction: the sand reaches the tip early, dehydrates and bridges. Over-padded only costs you fracture length that never gets propped.

Check the peak surface pressure against the burst rating, and remember the model carries no near-wellbore tortuosity and no surface treating iron, so treating pressure on the day is likely to be higher than the figure shown.

Read the limitations block on the printed report. It is short, it is specific, and it is there because the model has a scope and the page states its edges.

FastFrac is a design tool. It does not replace an engineer's judgement, a calibrated model, or a diagnostic injection test on the well in front of you.