Wolfcamp Frac Design Parameters

Midland Basin Wolfcamp B: hydraulic fracture design inputs and pump schedule for a single stage of a multi-stage horizontal well

Aegis Solutions Group, LLC | FastFrac | fastfrac.net

Compiled 20 October 2026

What this is. A starting set of frac design parameters for one stage of a Midland Basin Wolfcamp B horizontal, organised to match the FastFrac hydraulic fracture design software so it can be entered directly. Every entry carries a recommended value, a working range, and the source the number came from, and Section 8 gives a complete proppant schedule for the stage.

On sources, and a warning worth reading. Published Wolfcamp B data is thinner than the size of the play suggests. Operators do not publish completion details, and much of what is in the public record is five to ten years old or comes from modelled base cases rather than measurements. Where a value rests on a single study, or on general engineering practice with no citation behind it, the entry says so. The recommended column is not authoritative for your acreage. It is a starting point before you have your own logs and a DFIT.

What this does not give you is the answer. The fracture geometry, the treating pressures, the horsepower and the placement checks come from running the design. The complete set below, with the pump schedule at the back, is built into FastFrac as a worked example. Open it and press Compute.

1 The Wolfcamp play, the bench, and a nomenclature trap

Why Wolfcamp B, and one piece of naming that will mislead you if nobody flags it.

The Wolfcamp is the thickest and most drilled interval in the Midland Basin, divided by operators into benches A through D. Wolfcamp B is the workhorse, the bench with the longest horizontal production history and the only one with a large public completion dataset, a study of more than 3,100 Wolfcamp B wells. It is organic rich and clay bearing, which matters for the stress profile.

The trap. The operator naming (Wolfcamp A, B, C, D) and the stratigraphic naming used in much of the technical literature (Upper, Middle, Lower Wolfcamp) are not the same scheme. The largest public stress dataset in the basin, the Hydraulic Fracture Test Site-1, reports Upper and Middle Wolfcamp. As an approximation Upper Wolfcamp corresponds to Wolfcamp A and Middle Wolfcamp to Wolfcamp B, and this document uses that mapping, but it is an approximation and the boundary moves across the basin. When you pull a number from a paper, check which scheme it is using before you apply it to your bench.

Do not carry these numbers into the Delaware Basin. The Delaware Wolfcamp is deeper and strongly overpressured. Pore pressure, stress, treating pressure and fluid properties all differ materially. This document is Midland only.

2 Design identification

Free text, no effect on the calculation. Name the stage as well as the well, for example "Well name, Stage 20 of 45", because a single-stage design that gets separated from its context is not traceable to anything.

3 Well and completion data for a Wolfcamp horizontal

Well type - Horizontal

Recommended: Horizontal.

Reveals true vertical depth and liner ID, which is what you need, because pressure acts over vertical height while friction acts over pipe length and on a 10,000 ft lateral those are nowhere near the same number.

Measured depth

Recommended 14,500 ft. Range 10,000 to 21,000 ft.

This is the measured depth to the stage being treated, not to the toe. The recommended figure is a mid-lateral stage on a well with 8,500 ft TVD and a 10,000 ft lateral. A toe stage on the same well is near 19,000 ft and a heel stage near 10,000 ft, and the difference is worth roughly 1,500 psi of pipe friction, so the stage you pick changes the surface pressure materially.

Source: HFTS-1 well geometry, Kohli and Zoback (2021), which reports a vertical pilot to ~8,500 ft TVD and horizontal wells ~10,000 ft long. Lateral lengths around 10,000 ft are confirmed across 3,100+ Wolfcamp B wells by the TGS study.

True vertical depth

Recommended 8,500 ft. Range 7,000 to 9,500 ft.

Sets the hydrostatic head, the fracture pressure and the reservoir pressure. The Wolfcamp deepens toward the basin axis, so the range matters more than the midpoint.

Source: HFTS-1 vertical pilot well TVD, Kohli and Zoback (2021). The NETL Midland Wolfcamp simulation study uses 8,000 ft to the top of its Bench B model.

Casing - Liner ID

Recommended 5.5 in. OD, 20 lb/ft, P-110. ID and liner ID 4.778 in.

The standard Permian production string. FastFrac computes the burst rating from OD, weight and grade, and for this pipe it returns 12,600 psi.

The heavier 23 lb/ft wall at 4.670 in. ID is equally common and rates 14,658 psi. It buys burst margin and costs a little flow area, which raises friction. At the friction reduction assumed in Section 6 the lighter string is not the constraint on this design, so there is no reason to reach for the heavier one.

Source: general Permian completion practice. No single publication was found specifying the casing programme, so confirm against your own tally. The ID and burst follow from API dimensional and 5C3 data once OD, weight and grade are set.

Fracturing path

Recommended: down casing.

Plug and perf through the production casing is the near-universal Permian completion. There is no tubing in the hole during the treatment.

Number of parallel fractures (clusters per stage)

Recommended 8. Range 3 to 12.

This is the single most contested number in the whole set, and the public record genuinely disagrees. A modelled Midland base case uses 3 clusters per stage at 89 ft spacing in a 270 ft stage. Field practice reported by operators runs much tighter: 8 clusters in a 147 ft stage in one case, and a Permian study notes perforation spacing "consistently 25 ft". Eight clusters at 25 ft spacing in a 200 ft stage is consistent with the tighter reports and with where the industry has moved.

Consequence for the frac design. Cluster spacing follows from this and the stage length, and the injection rate is split equally between clusters, so this number divides the rate into each fracture. It also switches off the folds of increase, correctly, because that calculation assumes one fracture draining a circle.

Sources: ACS Energy and Fuels (2024) Midland geomodel base case for the 3-cluster figure; Sabalo Energy via AOGR for 8 clusters in 147 ft stages; OGJ limited-entry article for 25 ft perforation spacing.

Fracture complexity adjustment

0%. No equivalent-fracture adjustment applied.

The effective count is 8, equal to the primary cluster count. No nonzero percentage has been established for this example. Effective count = primary count x (1 + adjustment / 100). A nonzero value is an assumed sensitivity that changes the fracture calculations while retaining the physical perforation count. It does not simulate a branching network.

Perforations per primary fracture - Perforation diameter

Recommended 3 shots per cluster at 0.40 in. Range 2 to 8 shots, 0.32 to 0.42 in.

Enter shots per cluster, not per stage; FastFrac multiplies by the cluster count itself. With 8 clusters, 3 shots each and 0.40 in. holes at 95 bbl/min, the model returns about 1,840 psi of perforation friction, which is a sound limited-entry design.

Published Permian practice brackets this widely: 2 shots per cluster gave 5,500 psi of perforation drop in one extreme limited-entry test, 3 to 4 shots gave 1,900 to 2,000 psi, and a more conventional layout used 4 shots per foot at 0.42 in. Erosion then cut all of them, in one case below 600 psi by the end of the job.

Check the hole size against gun test data rather than the catalogue. One operator found real entrance holes smaller than the 0.42 in. the guns were designed for, and another measured variance as high as 24 per cent against expected diameters. Perforation friction goes as the fourth power of hole diameter, so a 20 per cent error here is a factor of two in the pressure drop.

Sources: OGJ, "Increased stage length complicates limited entry perforating" and "Designer stages improve Wolfcamp performance", for shot counts, hole sizes, measured pressure drops and the erosion behaviour.

4 Wolfcamp reservoir properties for fracture design

The weakest-sourced section in the document. Read the caveats.

Net pay thickness

Recommended 300 ft. Range 150 to 500 ft.

In FastFrac this is the permeable thickness that leaks, which caps the leakoff area. It is not the fracture height.

With the containment height at 600 ft this cap is active, and it matters. Only the middle 300 ft of a 600 ft fracture face stands against the Wolfcamp B bench, so the model leaks over half the face and returns a leak ratio of 0.50. That halves the fluid loss against an uncapped run.

There is a defensible argument for setting this to 600 instead. A fracture growing out of Wolfcamp B grows into Wolfcamp A above and C below, and those are the same organic-rich nanodarcy source rock, not impermeable barriers. On that reading the whole face leaks and net pay should match the height. The difference turns out to be small either way, so run it at 300 and at 600 and satisfy yourself that the choice does not drive your design decision before you settle on one.

Source: bench thickness inferred from the HFTS-1 cored intervals, 437 ft of continuous core through the Upper Wolfcamp and 158 ft through the Middle. No published Wolfcamp B net-pay cutoff study was found.

Average permeability

Recommended 0.0003 md (300 nd). Range 0.00005 to 0.001 md.

The published numbers do not agree, and the disagreement is a measurement-method artefact rather than real geology. One Ector County core study reports effective matrix permeability averaging 2.52 nanodarcy. A four-core lithofacies study across Glasscock, Sterling and Irion counties reports plug permeability of 0.001 to 0.197 md, which is three to five orders of magnitude higher. Crushed-rock and pulse-decay methods do not measure the same thing as a core plug under confining stress, and plug values on shale are commonly contaminated by microfractures opened during recovery.

The recommended value sits in the nanodarcy-to-low-microdarcy band that the broader literature supports for Wolfcamp matrix. It is a guess inside a band, not a measurement. Permeability drives both leakoff terms and the dimensionless conductivity, so run your design at the top and bottom of the range before you rely on the fluid efficiency.

Sources: UT Arlington core studies of Wolfcamp A, B, Dean and Spraberry; Fasken Ector County core study; Midland Basin lithofacies permeability study. A DOE NETL simulation of the same bench established its permeability by history matching production rather than by measurement, and says so.

Average porosity

Recommended 0.07. Range 0.04 to 0.10.

Reservoir porosity, not the proppant pack porosity entered later. Published Wolfcamp porosity runs 2 to 12 per cent with an average near 6. A Wolfcamp B and lower Spraberry facies study gives 6.9 per cent total against 3.8 per cent effective, and the NETL model uses 4.7 per cent matrix. The effective-versus-total distinction is the reason the published spread looks so wide.

Sources: EIA Permian Basin Part 2, Wolfcamp Shale Play of the Midland Basin; Wolfcamp B and lower Spraberry lithofacies study; NETL Midland Wolfcamp simulation study.

Reservoir fluid viscosity

Recommended 0.5 cp. Range 0.3 to 1.0 cp.

Live oil viscosity at reservoir conditions, used only in the reservoir-controlled part of the leakoff. The NETL Bench B model carries 39 degree API oil at 159 degrees F with a bubble point of 2,800 psia, which puts live-oil viscosity in the few tenths of a centipoise. The FastFrac Toolbox will estimate it from those three numbers.

Source: NETL Midland Wolfcamp reservoir simulation study fluid properties table. The viscosity itself is a correlation result, not a measured value.

Total compressibility

Recommended 15 x10^-6 psi^-1. Range 8 to 25.

Fluid plus pore volume. An undersaturated 39 degree API oil system at 7 per cent porosity lands in the low tens. Run the high end if your acreage is gassier, because a gas phase raises total compressibility sharply and that reduces the reservoir-controlled resistance to leakoff.

Source: no published Wolfcamp total-compressibility figure was found. This is standard reservoir engineering from the NETL fluid description. The Toolbox will compute it from the same inputs.

Reservoir pressure gradient

Recommended 0.50 psi/ft. Range 0.44 to 0.55 psi/ft.

The Midland Wolfcamp is at or slightly above hydrostatic, which is the main thing separating it from the Delaware. At HFTS-1 the hydrostatic gradient is 0.44 psi/ft and drilling mud weight ran about 0.53 psi/ft, which the authors treat as an upper bound on pore pressure because the wells were drilled nearly balanced. A regional estimate gives 0.46 to 0.52 psi/ft, and the NETL model implies 0.53.

Be careful with the 0.61 to 0.66 psi/ft figure that circulates for the Wolfcamp. It is a Delaware and regional-composite number and it is too high for the Midland Basin.

Sources: Kohli and Zoback (2021) for the 0.44 hydrostatic and 0.53 mud-weight bound; NETL model initial pressure of 4,265 psia at 8,000 ft.

Reservoir temperature

Recommended 160 degF. Range 140 to 180 degF.

FastFrac does not use this in the fracture calculation. It seeds the Toolbox and prints on the report.

Source: NETL Midland Wolfcamp model, bottomhole temperature 159 degrees F.

Drainage area - Hole diameter - Skin

Recommended 160 acres, 8.75 in., skin 0.

All three feed only the folds of increase, which FastFrac will not report for a multi-cluster stage anyway, so on this design they are inert. Fill them for the record. The 160 acres reflects a 10,000 ft lateral on roughly 660 to 880 ft spacing; HFTS-1 observed well-to-well communication at 660 ft.

Source: HFTS-1 programme reports for the 660 ft spacing observation.

5 Wolfcamp rock mechanical properties

Two entries with a decent source, and one that is the largest assumption in the design.

Young's modulus

Recommended 2.5 x10^6 psi. Range 1.0 to 3.5.

A 2024 Midland Basin study built its Wolfcamp A and B geomodel on static Young’s modulus of 1.0 to 2.6 million psi. That is the right kind of number for FastFrac, which wants static stiffness.

Do not take a dynamic log value straight from a sonic and density run. Dynamic moduli on Wolfcamp run materially higher, often 4 to 6 million psi, and using one here will give you a fracture that is too narrow and too long. Convert to static with a local correlation first.

Source: ACS Energy and Fuels (2024), Midland Basin integrated modelling study, static model properties for Wolfcamp A and B.

Poisson's ratio

Recommended 0.22. Range 0.18 to 0.28.

Same source and same study. It enters only through the plane strain modulus and moves the answer far less than Young’s modulus does.

Source: ACS Energy and Fuels (2024), Poisson’s ratio 0.18 to 0.28.

Fracture gradient

Recommended 0.70 psi/ft. Range 0.60 to 0.80 psi/ft.

The same Midland geomodel carries minimum horizontal stress of 4,200 to 6,000 psi across the Wolfcamp A and B section, which at 8,500 ft TVD is 0.49 to 0.71 psi/ft. The recommended 0.70 sits at the top of that, which is appropriate for the clay-rich and organic-rich Wolfcamp B specifically.

Why the B bench sits high. The HFTS-1 work found that strata with high clay and organic content carry higher least principal stress, because those are the most compliant components of the matrix and they relax viscously over geologic time. That is the opposite of the intuition that soft rock means low stress, and it is also why those same layers act as barriers to vertical fracture growth.

If you have an ISIP, do not enter it here. At HFTS-1 instantaneous shut-in pressures ran 2 to 5 MPa, roughly 300 to 700 psi, above the true minimum stress, because of perforation friction, near-wellbore tortuosity and stress shadow. Use closure pressure from a DFIT falloff, not ISIP.

Sources: ACS Energy and Fuels (2024) for the stress magnitudes; Kohli and Zoback (2021) for the stress-relaxation mechanism and the ISIP correction.

Containment height

Recommended 600 ft. Range 250 to 600 ft.

This is where the published data is most interesting and most uncomfortable.

At HFTS-1 the microseismic cloud indicated roughly 600 ft of vertical fracture extent. The slant core well drilled back through the stimulated rock found about 30 ft of propped height in the Upper Wolfcamp, around 5 per cent of the microseismic extent. Those two numbers differ by a factor of twenty and both are real measurements of different things.

FastFrac’s containment height is the created fracture height, since it governs area and width, so the microseismic figure is the right family of number and the propped 30 ft is not. The recommended value is therefore 600 ft, consistent with the microseismic. It is an upper bound, because the cloud includes rock that was stimulated and never propped, so treat it as the generous end of a bracket rather than a measurement of the fracture.

At 600 ft the fracture almost certainly leaves the bench. Centred on a lateral landed in a 300 ft bench it puts roughly 150 ft above and below outside Wolfcamp B, into Wolfcamp A and C. In stacked Midland development that reaches the landing zone of a well in the adjacent bench, and HFTS-1 observed well-to-well communication at 660 ft spacing. The HFTS-1 completions used zipper and simultaneous fracturing specifically to restrain upward growth into a lower-pressure zone.

Run 250 ft and 0 as sensitivities. At 250 ft the half length roughly doubles, to 1,289 ft. At 0 the fracture goes radial. The conclusions that survive all three are the ones to trust, because nobody measured this height on your well.

Sources: GTI and DOE HFTS-1 programme reports and AOGR coverage, for the 600 ft microseismic extent, the 30 ft propped height and the 5 per cent ratio.

6 Fracturing fluid: slickwater design

Fluid viscosity

Recommended 3 cp. Range 1 to 10 cp.

Current Permian practice is predominantly slickwater, which is a friction-reduced water of a few centipoise. The upper end of the range covers a light linear gel in a hybrid design, where gel stages are used late to carry the coarser proppant.

Source: general Permian completion practice; slickwater is described as the carrier fluid in the Wolfcamp and Spraberry studies reviewed. No published Wolfcamp-specific rheology measurement was found.

Friction reduction

Recommended 75 per cent. Range 60 to 80 per cent.

Entered as the percentage by which pipe friction is reduced, so 75 means the model multiplies friction by 0.25. It is applied to the pipe and annulus only, never to the perforation drop, because the polymer does nothing where fluid passes through a hole rather than along a wall.

It is the most leveraged number in the document. On this well each five percentage points is worth about 1,113 psi at surface. At zero the job would need 26,801 psi, far above the casing burst rating, so friction reducer is not optional here and anything below 62 per cent puts the treatment over burst on this string at 95 bbl/min.

Three independent lines of evidence put this near 75, and 75 is close to the physical ceiling rather than past it. A Permian-focused study measured about 75 per cent reduction at roughly 1 pound per thousand gallons on field water from both the Delaware and Midland basins. Separately, the only published Permian treating pressures found, about 8,000 psi in one field case and 8,800 to 9,200 psi in another at 90 to 100 bbl/min, correspond to reductions in the high seventies on geometry like this one. And polymer drag reduction has a known upper bound, Virk’s maximum drag reduction asymptote, which sits near 80 per cent off Newtonian turbulent friction. So 75 is near the limit of what the physics allows, which is the right place for a well-performing modern reducer and the wrong place for a tired one.

The argument against going higher. The laboratory figure is measured on clean fluid in a friction loop. In the pipe the polymer shear-degrades on the way down and loses effectiveness as sand loading climbs, so field performance sits at or below the laboratory number rather than above it. Treat 75 as the upper case and 60 to 65 as the range late in a stage.

It can be calibrated on the well. At instantaneous shut-in both pipe friction and perforation drop vanish, so surface treating pressure minus ISIP is the total friction loss at that rate. Take one stage, subtract the perforation drop of about 1,840 psi, run this design at zero friction reduction to get the unreduced pipe friction, and your reduction is one minus the ratio. For reference the model predicts treating pressure sitting 7,265 psi above the ISIP at 95 bbl/min with 75 per cent. A larger gap on location means the reducer is underperforming the assumption here, and the surface pressure will follow.

One stated limitation. The model holds this constant for the whole stage, while in the field it falls away as sand loading climbs. A single number is already an approximation of something that drifts during the job.

Sources: laboratory friction-reduction performance on Delaware and Midland field water, from a published high-performance friction reducer study. For method rather than magnitude, SPE HFTC 2022, "New Casing Friction Model for Slickwater: Field Data Validation", which used bottomhole gauges in the lateral across six friction reducer types to separate casing friction from near-wellbore losses; that is the right way to measure this and its figures are not in the abstract. No field-measured Wolfcamp percentage was found.

Fluid specific gravity

Recommended 1.02. Range 1.00 to 1.05.

Fresh or lightly produced water. Permian operations run heavily on recycled produced water, which carries dissolved solids and sits at the top of the range.

Source: none specific. Water density at known salinity.

7 Proppant selection and mesh size

Mesh size

Recommended: run the stage twice, as 100 mesh and as 40/70.

A real Permian stage is not one proppant. It leads with 100 mesh and steps up to 40/70, and almost all of it is regional in-basin sand rather than Northern White. FastFrac carries one cut per design, so the stage is run twice, once per cut.

Run both and compare them. The two cuts give materially different answers on proppant settling, on bridging and on fracture conductivity, and the comparison is the whole reason the industry sequences them the way it does. A cut too coarse for the width available bridges at the perforations, which is the near-wellbore screenout the sequencing avoids. The same schedule serves for both runs; only the mesh size field changes.

Source: general Permian practice. The TGS Wolfcamp B dataset reports proppant loading but not the cut distribution.

Proppant specific gravity

Recommended 2.65. Range 2.65 to 2.72.

Regional Permian sand is ordinary silica at 2.65. Nothing in a Wolfcamp B slickwater design calls for ceramic.

Source: supplier data for silica sand; the monograph gives 2.65 for sands.

Pack porosity

Recommended 0.37. Range 0.35 to 0.40.

Published unstressed values for sand. Not a property of the mesh size. It enters the pack permeability as the cube, so it moves the fracture conductivity as strongly as the grain size does.

Source: published proppant pack data; see the FastFrac Input Guide for the bulk density conversion.

Conductivity damage factor

Recommended 0.5. Range 0.3 to 0.6.

Regional sand at Wolfcamp closure stress crushes, and crushing is the main reason regional sand is discounted against Northern White. Add gel residue if you run a hybrid, and multiphase flow once the well produces. The factor scales the fracture conductivity directly.

Note the net stress on the pack on day one: about 1,700 psi, because closure is 5,950 psi and pore pressure is 4,250 psi. That is the benign initial condition. As the well depletes, pore pressure falls and the net stress on the pack climbs toward the full 5,950 psi, which is where regional sand crushing occurs. The damage factor is carrying that future, not the day-one condition.

Source: none published for Wolfcamp specifically. Engineering judgement from the closure stress and the proppant type.

8 Injection rate and the stage pump schedule

Injection rate

Recommended 95 bbl/min. Range 80 to 100 bbl/min.

Total slurry rate across all clusters. FastFrac divides it by the cluster count, so at 8 clusters each fracture takes 11.9 bbl/min.

The rate, the casing and the friction reducer are a coupled choice, and the binding limit is usually the surface equipment rather than the pipe. Most United States shale spreads are rated to 10,000 psi working pressure, with 15,000 psi classes reserved for deeper targets, and that class is usually reached before the casing burst margin runs out. Which of the two binds on your well is worth establishing before you order the spread, and it is a rate sweep in the model rather than a number this document can give you.

Sources: Sabalo Energy reported pumping at 100 bbl/min in the Midland Wolfcamp; a separate Wolfcamp and Spraberry study used slickwater at 95 bbl/min; a published treating-pressure example reports 3,780 to 4,200 gpm, which is 90 to 100 bbl/min.

Which stage you are treating moves the surface pressure more than anything else in this document, because pipe friction scales with the length of pipe the fluid travels. The same design, same rate, same reducer, can sit inside a 10,000 psi spread at the heel and need a 15,000 psi one at the toe of a 10,000 ft lateral. A design document that quotes one treating pressure without saying which stage it describes is not telling you enough to order equipment. Enter the measured depth of the stage being treated.

Stage size. The design below is built to the published field averages: a 220 ft stage carrying 1,923 lb of proppant per lateral foot in 31 bbl of fluid per foot. The TGS study of more than 3,100 Wolfcamp B wells gives an average proppant loading of 1,984 lb/ft, and a Midland modelling study uses 30.5 bbl/ft of fluid. An enhanced design reported by one operator ran 2,400 lb/ft, so the recommended intensity is mainstream rather than aggressive.

One mesh size runs through the whole schedule. FastFrac carries a single sieve cut per design, and this one is 40/70 from the first sand stage to the tail-in. The field job it is built from leads with 100 mesh and steps up, which is a sequence the input page cannot hold in one run. Run this same schedule twice instead, once as 100 mesh and once as 40/70. Nothing in the volumes or concentrations changes between the two; only the mesh size field does.

Proppant concentration is given in pounds per gallon of clean fluid, the field convention, and the volumes are slurry volumes, which is what FastFrac expects. The displacement is one wellbore volume for 14,500 ft of 5.5 in. 20 lb/ft casing; FastFrac computes it and will disagree if you change the depth or the pipe.

9 Sources for these Wolfcamp design parameters

Kohli, A. and Zoback, M. (2021) "Stratigraphically Controlled Stress Variations at the Hydraulic Fracture Test Site-1 in the Midland Basin, TX," Energies 14(24):8328. Open access. The largest public stress dataset found for the basin: DFITs in vertical and horizontal wells, stress gradients, and the stress-relaxation mechanism. doi.org/10.3390/en14248328

ACS Energy and Fuels (2024) "Unveiling Well Performance through Integrated Numerical Modeling and Basin-Scale Data Analysis in the Midland Basin." Static Young’s modulus, Poisson’s ratio, minimum and maximum horizontal stress, and a modelled completion base case for Wolfcamp A and B.

DOE NETL (2019) Wolfcamp Shale / Midland Basin reservoir simulation study. Bench B model porosity, initial pressure, bottomhole temperature, oil gravity and bubble point. Note its permeability was set by history matching, not measurement.

GTI and DOE, HFTS-1 programme reports, and AOGR coverage The Hydraulic Fracturing Test Site-1 results: slant core through the stimulated volume, 595 ft of core recovered, roughly 30 ft of propped height against about 600 ft of microseismic extent, and well-to-well communication at 660 ft spacing.

TGS and ComboCurve Midland Basin Wolfcamp B study, more than 3,100 wells. Average proppant loading 1,984 lb/ft at lateral lengths around 10,000 ft. The largest field dataset found for this bench.

EIA Permian Basin Part 2: Wolfcamp Shale Play of the Midland Basin. Regional porosity and stratigraphy.

Oil and Gas Journal "Increased stage length complicates limited entry perforating" and "Designer stages improve Wolfcamp performance." Shot counts, entrance hole diameters, measured perforation pressure drops and erosion behaviour.

AOGR "Permian Basin Operators Keep 2020 Focus Fixed On Wolfcamp Plays." Stage lengths, cluster counts, pump rates and proppant loadings reported by operators.

Friction reducer performance A published high-performance friction reducer study measuring roughly 75 per cent friction reduction at about 1 pptg on Delaware and Midland field water, laboratory derived. For methodology, SPE HFTC 2022, "New Casing Friction Model for Slickwater: Field Data Validation, Application, and Optimization for Hydraulic Fracturing," which used downhole gauges to separate casing friction from perforation and near-wellbore losses.

Core permeability studies UT Arlington theses on Wolfcamp A, B, Dean and Spraberry pore structure; an Ector County core study reporting 2.52 nd effective matrix permeability; a Glasscock, Sterling and Irion county lithofacies study reporting 0.001 to 0.197 md on plugs.

Parameters marked in their entries as having no source are general engineering practice, not published Wolfcamp measurements. Those are friction reduction, fluid specific gravity, total compressibility, the casing programme and the conductivity damage factor.