RFour Energy · Field Notes

Hydraulic Fracturing — Candidate, Design, Diagnosis

Q: Which wells are good hydraulic fracturing candidates?

Two distinct cases. The first is low-permeability rock, where the fracture provides a high-conductivity path that the matrix cannot, and the prize scales with fracture length. The second is a damaged well in moderate permeability, where a short but highly conductive fracture bypasses near-wellbore damage, and the prize scales with conductivity rather than length. A well is a poor candidate when permeability is already high enough that the matrix can deliver, when the pay is thin and bounded by water or gas with little stress contrast to contain height growth, when cement quality cannot support isolation, or when the remaining reserves do not justify the treatment.

Q: What dimensionless fracture conductivity should be targeted?

Dimensionless fracture conductivity compares the capacity of the fracture to carry flow along its length with the capacity of the formation to deliver flow into it. The target depends entirely on what is held fixed. If fracture length is fixed and conductivity is being chosen, values of roughly ten to thirty are the accepted range and beyond about thirty the fracture behaves as infinite conductivity. If instead the volume of proppant is fixed and the question is how to distribute it between length and width, the optimum falls to about 1.6 for low proppant numbers. The two answers are not in conflict; they answer different questions.

Q: What does the Nolte-Smith plot show?

It plots net pressure, the treating pressure above fracture closure, against pumping time on log-log axes, and the slope identifies what the fracture is doing. A modest positive slope is consistent with confined-height extension; a flat or slightly declining response suggests height growth or fluid loss into natural fractures; a steep rise indicates restricted extension approaching a screenout. Nolte and Smith framed this around a critical pressure beyond which extension is significantly reduced and either a screenout or unwanted height growth follows.

Q: Why do created, propped and effective length differ?

Created length is how far the fluid propagated, propped length is how far proppant was actually carried and remained at closure, and effective length is the portion that contributes to production once the fracture has cleaned up and closed under stress. Each is shorter than the one before it. Diagnostics measure different things: microseismic tends to map the created or stimulated extent, while production and pressure transient analysis see only the effective length, and the difference between them is routinely large.

A frac is not a treatment you apply to a well that is underperforming. It is a specific answer to a specific limitation, and the first engineering act is deciding whether the well has that limitation at all.

RFour Energy · Production Engineering Series

Hydraulic fracturing creates a high-conductivity plane in the rock and props it open so it survives closure stress. Everything else — fluid chemistry, proppant selection, pump schedules, stage counts, diagnostics — exists to control the geometry and conductivity of that plane, or to find out afterwards what actually happened. The discipline splits cleanly into four questions, and they are best kept separate: is this well a candidate, what geometry and conductivity should the fracture have, did the pumping do what was designed, and what did the reservoir actually get. The last one is the least often answered honestly.

Candidate Selection

There are two genuinely different reasons to fracture a well, and confusing them produces designs that optimise the wrong variable.

Low permeability. The matrix cannot deliver fluid to the wellbore fast enough at any drawdown. The fracture supplies a flow path the rock does not have, and the prize scales with length — reach, not capacity.
Damage in moderate permeability. The rock can deliver, but a damaged zone near the wellbore is throttling it. A short fracture that simply crosses the damaged region restores the well, and the prize scales with conductivity — capacity, not reach.

FIG. 01Screening on the two variables that decide the kind of design, not merely whether to treat. Low permeability rewards reach; damage rewards capacity. The right-hand column is the trap: a high-permeability well that is underperforming usually has a damage or completion problem, and a long fracture is an expensive way to address it. The disqualifiers on the right override the quadrant entirely — height containment and zonal isolation are prerequisites, not design variables.

Two disqualifiers deserve emphasis because they are physical rather than economic. Without a stress contrast above and below the pay, fracture height is not contained, and a treatment designed for length grows vertically into water or gas instead. And without competent cement, there is no isolation to fracture into — pressure finds the annulus. Neither can be fixed by a better fluid.

Design — The Mechanics Underneath

A fracture opens because injection raises pressure above the minimum in-situ stress. The quantity that matters through the whole design is net pressure — treating pressure minus closure pressure — because it is net pressure that creates width, and width is what admits proppant.

The classical width models remain the vocabulary of the field. PKN, from Perkins and Kern and completed by Nordgren, assumes a fracture much longer than it is tall, with plane-strain in the vertical section — net pressure increases as the fracture extends.^[1][2] KGD, from Khristianovich and Zheltov with Geertsma and de Klerk, assumes plane-strain horizontally, appropriate when height exceeds length — and net pressure decreases with extension.^[3][4] That opposite sign is not a curiosity; it is the basis of pressure diagnosis during pumping.

Conductivity — and why the “optimum” depends on the question

A propped fracture is only useful if it can carry flow along its length faster than the formation feeds it. That comparison is the dimensionless fracture conductivity, and its consequence is captured by Prats's effective wellbore radius: a fractured well behaves like an unfractured well with a much larger wellbore.^[5]

FIG. 02The conductivity curve, computed from the Cinco-Ley and Samaniego pseudo-skin relation.^[6] Effective wellbore radius rises steeply with conductivity and then flattens: by F_CD ≈ 30 it has reached about 0.48 x_f, which is why beyond thirty a fracture is treated as infinite-conductivity. The two markers answer different questions and are often quoted as if they contradicted. With length fixed, ten to thirty is the accepted target range. With proppant volume fixed — the unified-fracture-design question of how to distribute a given mass between length and width — the optimum falls to about 1.6 at low proppant number,^[7] where r_w′/x_f is 0.25, precisely half the maximum. Trading conductivity for length is the whole point.

Fluids and proppant

Slickwater — water with friction reducer. Low viscosity, poor proppant carrying, but cheap, low-damage and capable of creating complex geometry in brittle rock. Requires high rates and fine proppant.
Linear and crosslinked gels — high viscosity, excellent transport, wider fractures. The cost is residue and conductivity damage, which is what breakers exist to limit.
Energised and foamed fluids — nitrogen or CO₂ assisted; less water in the formation, faster cleanup, favoured in water-sensitive or under-pressured rock.
Proppant — sand where closure stress allows; resin-coated for flowback control; ceramic where stress crushes sand. Selection is a closure-stress decision first and a cost decision second, because crushed proppant destroys precisely the conductivity the design was built on.

Execution — Reading the Pressure While It Happens

Before the main treatment, a calibration injection — minifrac or DFIT — establishes closure pressure, leakoff behaviour and near-wellbore friction. Closure is the anchor for everything: net pressure cannot be computed without it, and the entire diagnostic framework is built on net pressure.

During pumping, the primary real-time diagnostic is the Nolte-Smith plot: net pressure against time on log-log axes, where the slope indicates what the fracture is doing.^[8]

rise as a confined fracture extends. Departures from that rise are the diagnosis. Nolte & Smith framed this around a critical pressure beyond which extension is much reduced.

FIG. 03The pressure record as a live diagnostic. A gentle positive slope is consistent with a height-confined fracture extending as PKN predicts; a flat or declining response signals height growth or fluid loss into natural fissures; a steep rise means extension has become restricted and a screenout is developing. Nolte and Smith built the framework around a critical pressure at which fracture extension is significantly reduced, after which either a screenout or unwanted height growth follows — and they demonstrated it on five field treatments.^[8] This plot is the reason a treatment can be changed while it is still pumping. The three segments here are drawn to show the sense of each slope rather than calibrated values — the axes carry no decade marks, and the diagnosis in practice comes from comparing the observed slope against the one the assumed geometry predicts, not from reading a number off the chart.

The operational vocabulary follows from it: a pad to open width before proppant arrives, a proppant concentration ramp, a step-down test to separate perforation friction from near-wellbore tortuosity, and a deliberate decision about whether a tip screenout is a failure or, in a frac-pack, the design intent.

Monitoring and Post-Treatment Evaluation

Diagnostics divide by what they can physically see, and treating them as interchangeable is a persistent error.^[9][10]

Method	What it observes	What it cannot tell you
Treating pressure	Net pressure behaviour, in real time	Where the fracture went
Microseismic	Shear events around the growing fracture — stimulated extent	Whether proppant reached there, or whether it conducts
Tiltmeter	Deformation → fracture orientation and dip	Length or conductivity
Fibre (DAS / DTS)	Fluid and proppant distribution between clusters	Far-field geometry
Tracers	Which stages and clusters contribute to flow	Fracture dimensions
Post-frac PTA / RTA	Effective half-length and conductivity	What was created but is not producing

One diagnostic deserves naming because it turns post-frac pressure data into a conductivity number rather than a curve match. Where flow is bilinear — transient linear flow occurring simultaneously in the fracture and in the formation feeding it — pressure plotted against the fourth root of time falls on a straight line, and that slope is inversely proportional to h(k_fb)^½.^[6] It is one of the few places in fracture evaluation where a plot yields conductivity directly.

FIG. 04The three lengths, and why quoting one for another flatters a treatment. Created length is where fluid propagated; propped length is where proppant was carried and remained at closure; effective length is the part that actually contributes after cleanup and under closure stress. Each is shorter than the one before. Microseismic tends to see the first, production and pressure transient analysis only the last, and resolving the difference between them is a recognised problem in its own right.^[11] Each wedge is drawn tapering to zero at its tip, which is the physical width profile of an internally pressurised crack rather than a drafting choice.^[14]

Published Field Applications

Diagnostics integrated at field scale

The clearest demonstrations of the point above come from campaigns where several diagnostics were run together rather than in isolation. A published Marcellus study integrated fracture diagnostics with engineering data across a development, precisely so that treatment design could be tied to what the diagnostics showed rather than to what the pump schedule intended.^[12]

Drainage mapping and the effective-length problem

The gap between created and effective length is not an academic worry; it has been the subject of dedicated field work. A published Bakken case history addressed drainage mapping and effective fracture length directly, combining well-to-well observations with modelling to establish how far the fractures were actually draining — as distinct from how far they were mapped as extending.^[13] The same group's earlier work framed the general problem of resolving created, propped and effective fracture length as a single reconciliation exercise rather than three separate measurements.^[11]

And the honest reading

What the published record supports is narrower than the marketing around it. Diagnostics reliably distinguish where fluid went from what produces, and the difference is routinely large. Treatments that were designed on created length and evaluated on created length will look better than they are, and the correction — running production-based evaluation and accepting a shorter effective length — is what turns a campaign into a learning system rather than a repeated assumption.

The pumps record what was injected. Only the reservoir records what was achieved, and it answers slowly.

The counter-evidence: most of the treatment may not be producing

The section above would be incomplete without the finding that most challenges the whole enterprise. A study that acquired and interpreted production logs from more than 100 horizontal shale wells across multiple basins found production to be highly variable along the wellbore — and quantified it: in some basins two-thirds of gas production came from only one third of the perforation clusters, and across all basins almost one third of all perforation clusters were not contributing to production at all.^[16]

Read that against the design section. A pump schedule is built cluster by cluster and paid for cluster by cluster; if a third of them contribute nothing, then a third of the proppant, fluid, horsepower and pumping time bought nothing. The failure is not in the fracture mechanics — the models in this article are sound — it is in placement between clusters, which limited entry, diversion and cluster spacing exist to control and evidently often do not.

It also reframes every length debate above. Arguing about created versus effective half-length assumes the cluster produced at all. The published record says that assumption is wrong about a third of the time, which is a larger correction than most of the design refinements the industry argues over.

The honest summary of the field record: the physics of a single fracture is well understood, and the distribution of many fractures along a wellbore is not.

Validation

The width and net-pressure models follow Perkins and Kern^[1] and Nordgren^[2] for the PKN geometry, and Khristianovich and Zheltov^[3] with Geertsma and de Klerk^[4] for KGD; the underlying crack-opening solution is Sneddon and Elliott's.^[14] The effective wellbore radius concept is Prats's,^[5] and the conductivity curve computed for Fig. 02 uses the Cinco-Ley and Samaniego pseudo-skin relation,^[6] which also supplies the convention that F_CD above about 30 is treated as infinite conductivity. The proppant-constrained optimum of about 1.6 is the unified-fracture-design result at low proppant number.^[7] The pressure-slope diagnosis in Fig. 03, including the critical pressure and its consequences, is Nolte and Smith's, demonstrated on five treatments.^[8] Fracture-diagnostic capabilities and their limits follow Warpinski^[9] and Cipolla and Wright.^[10] The distinction between created, propped and effective length is Cipolla, Lolon and Mayerhofer's,^[11] with field applications in the Marcellus^[12] and the Bakken.^[13] General treatment design and post-treatment evaluation follow Economides and Nolte.^[15] The counter-evidence on cluster contribution — the proportion of perforation clusters producing little or nothing across more than a hundred logged horizontal wells — is Miller, Waters and Rylander’s.^[16]

References

Perkins, T.K. & Kern, L.R. (1961). Widths of Hydraulic Fractures. Journal of Petroleum Technology 13(9), 937–949; SPE-89.
Nordgren, R.P. (1972). Propagation of a Vertical Hydraulic Fracture. SPE Journal 12(4), 306–314; SPE-3009.
Khristianovich, S.A. & Zheltov, Y.P. (1955). Formation of Vertical Fractures by Means of Highly Viscous Liquid. Proceedings of the 4th World Petroleum Congress, Section II, Rome, 579–586.
Geertsma, J. & de Klerk, F. (1969). A Rapid Method of Predicting Width and Extent of Hydraulically Induced Fractures. Journal of Petroleum Technology 21, 1571–1581; SPE-2458.
Prats, M. (1961). Effect of Vertical Fractures on Reservoir Behavior — Incompressible Fluid Case. SPE Journal 1, 105–118; SPE-1575-G, doi:10.2118/1575-G. Introduces the effective (equivalent) wellbore radius for a fractured well. Note the convention: the classical result is an effective radius of about one quarter of the fracture length measured tip to tip, which is one half of the half-length — the same 0.5 x_f plateau reached in Fig. 02. The two statements are identical and are often mistaken for a discrepancy.
Cinco-Ley, H. & Samaniego, F. (1981). Transient Pressure Analysis for Fractured Wells. Journal of Petroleum Technology 33(9), 1749–1766; SPE-7490-PA, doi:10.2118/7490-PA. Source of the pseudo-skin relation used to compute Fig. 02 and of the convention that F_CD > 30 is treated as infinite conductivity. Also establishes the bilinear-flow method: transient linear flow in both fracture and formation gives a straight line on pressure versus the fourth root of time, with slope inversely proportional to h(k_fb)^½.
Unified fracture design — the body of work by Valkó and Economides and, for the result quoted here, Daal and Economides (2006). For proppant numbers below about 0.1, a dimensionless fracture conductivity near 1.6 maximises productivity when the proppant volume rather than the fracture length is what is held fixed. Cited as a body of work rather than a single paper because the 1.6 result is reported across several publications in that line.
Nolte, K.G. & Smith, M.B. (1981). Interpretation of Fracturing Pressures. Journal of Petroleum Technology 33(9), 1767–1775; SPE-8297-PA, doi:10.2118/8297-PA. Identifies confined-height extension, uncontrolled height growth and a critical pressure beyond which extension is significantly reduced; demonstrated on five treatments. See also Nolte, K.G. (1979), Determination of Fracture Parameters from Fracturing Pressure Decline, SPE-8341, and Nolte, K.G. (1986), A General Analysis of Fracturing Pressure Decline with Application to Three Models, SPE Formation Evaluation 1(6), 571–583; SPE-12941-PA.
Warpinski, N.R. (1996). Hydraulic Fracture Diagnostics. Journal of Petroleum Technology 48(10), 907–910; SPE-36361.
Cipolla, C.L. & Wright, C.A. (2000). State-of-the-Art in Hydraulic Fracture Diagnostics. SPE-64434-MS, SPE Asia Pacific Oil and Gas Conference, Brisbane.
Cipolla, C.L., Lolon, E.P. & Mayerhofer, M.J. (2009). Resolving Created, Propped, and Effective Hydraulic-Fracture Length. SPE Production & Operations 24(4), 619–627; SPE-129618-PA.
Mayerhofer, M.J., Stegent, N.A., Barth, J.O. & Ryan, K.M. (2011). Integrating Fracture Diagnostics and Engineering Data in the Marcellus Shale. SPE-145463, SPE Annual Technical Conference and Exhibition, Denver.
Cipolla, C., Craig, D., Litvak, M., Prasad, R.S. & McClure, M. (2020). Case History of Drainage Mapping and Effective Fracture Length in the Bakken. SPE-199716-MS, SPE Hydraulic Fracturing Technology Conference, The Woodlands.
Sneddon, I.N. & Elliott, H.A. (1946). The Opening of a Griffith Crack Under Internal Pressure. Quarterly of Applied Mathematics 4, 262–267.
Economides, M.J. & Nolte, K.G. (eds.). Reservoir Stimulation (3rd ed.). John Wiley & Sons. Standard reference for treatment design, fluids and proppants, and post-treatment evaluation of fractured well performance.
Miller, C.K., Waters, G.A. & Rylander, E.I. (2011). Evaluation of Production Log Data from Horizontal Wells Drilled in Organic Shales. SPE-144326-MS, North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14–16 June 2011; doi:10.2118/144326-MS. Production logs from more than 100 horizontal shale wells across multiple basins: in some basins two-thirds of gas production came from one third of the perforation clusters, and across all basins almost one third of clusters were not contributing to production.

Frequently Asked Questions

Which wells are good hydraulic fracturing candidates?

Two cases. Low-permeability rock, where the fracture supplies a flow path the matrix lacks and the prize scales with length. And a damaged well in moderate permeability, where a short highly conductive fracture bypasses the damage and the prize scales with conductivity. Poor candidates: permeability already sufficient, thin pay with close contacts and no stress barrier to contain height, cement unable to support isolation, or too little remaining oil to pay for the job.

What dimensionless fracture conductivity should be targeted?

It depends on what is held fixed. With length fixed and conductivity being chosen, roughly ten to thirty is the accepted range, and beyond about thirty the fracture behaves as infinite conductivity. With proppant volume fixed and the question being how to split it between length and width, the optimum falls to about 1.6 at low proppant number. The two are not in conflict — they answer different questions.

What does the Nolte-Smith plot show?

Net pressure against pumping time on log-log axes. A gentle positive slope is consistent with confined-height extension; flat or declining suggests height growth or loss into natural fissures; a steep rise means restricted extension and a developing screenout. Nolte and Smith framed it around a critical pressure beyond which extension is significantly reduced.

Why do created, propped and effective length differ?

Created is where fluid went, propped is where proppant remained at closure, effective is what produces after cleanup under closure stress — each shorter than the last. Microseismic tends to see the created extent; production and pressure transient analysis see only the effective length, and the difference is routinely large.