type-curve analysis, Oil & Gas Glossary

What Is Type Curve Analysis?

Type curve analysis is a reservoir engineering method for interpreting well performance and estimating reserves by matching a well's production or pressure history to a set of dimensionless theoretical curves (type curves) derived from analytical or numerical solutions of the diffusivity equation, enabling estimation of permeability-thickness, skin factor, drainage area, and ultimate recovery from surface production data without requiring well shut-in for pressure transient testing.

Key Takeaways

Type curves are dimensionless plots of production rate or pressure versus time on log-log or semi-log scales derived from reservoir flow equations.
Fetkovich type curves (1980) combine early transient flow and late boundary-dominated decline on a single plot for single-layer reservoirs.
Blasingame, Agarwal-Gardner, and Flowing Material Balance type curves extend the method to variable-rate production histories.
Type curve matching requires rate and pressure history; the dimensionless match point yields permeability-height, skin, and drainage area.
In tight and unconventional reservoirs, specialised type curves account for hydraulic fracture geometry and stimulated reservoir volume.

How Type Curve Analysis Works

Type curve analysis exploits the mathematical similarity between dimensionless reservoir flow solutions and actual well production data. The analytical solutions to radial flow equations in a reservoir of known geometry, permeability, and boundary conditions produce dimensionless rate-time relationships that have characteristic shapes on log-log plots. By plotting actual well production data on the same log-log axes (or by transforming actual data into dimensionless variables) and matching the shape of the actual data to the pre-computed type curve family, reservoir properties can be inferred from the match parameters.

The Fetkovich (1980) type curves are the most widely used for conventional well analysis. They plot dimensionless rate (qDd) versus dimensionless time (tDd) with the dimensionless drainage radius (reD = re/rw) as a parameter family. The curves show two regimes: an early transient period where rate decline is controlled by radial flow from the reservoir (the portion that looks like pressure transient response) and a late boundary-dominated period where all pressure waves have reached the drainage boundary and the well enters exponential decline. Matching the actual production data to these curves yields qDd and tDd match points from which permeability-thickness and drainage area can be calculated, and the ultimate recovery from the boundary-dominated portion of the curve can be extrapolated.

Type Curve Analysis Applications Across International Jurisdictions

In Canada, type curve analysis is a standard component of reserve evaluation for WCSB tight gas and conventional oil wells. AER reserve auditors and independent qualified reserve evaluators use Blasingame or Agarwal-Gardner type curve analysis for unconventional Montney and Duvernay horizontal wells where conventional pressure transient analysis requires uneconomically long shut-in periods. The Canadian Oil and Gas Evaluation Handbook (COGEH), referenced by AER regulatory submissions, recognises type curve analysis as an accepted method for reserve estimation when production history is of sufficient duration and quality. Montney horizontal well type curve analysis using Wattenbarger linear flow type curves (appropriate for tight matrix reservoirs with hydraulic fractures) is standard practice for multi-well pad development planning.

In the United States, type curve analysis is the primary reserve estimation method for unconventional tight oil and gas wells (Permian Basin, Bakken, Eagle Ford, Marcellus, Utica) where pressure transient testing is impractical and the production history of the first 1-3 years provides the basis for EUR (estimated ultimate recovery) projection. The SEC reserve reporting rules require that reserves be estimated using methods appropriate to the available data; type curve analysis satisfies this requirement for unconventional wells with sufficient production history. EIA uses aggregated type curves for tight oil and gas plays to estimate production decline rates in its Annual Energy Outlook. In Norway, Sodir-regulated field development plans for NCS wells with complex multilateral completions use numerical type curves from reservoir simulation to plan production profiles.

Fast Facts

The Fetkovich type curves were published in a landmark 1980 SPE paper (SPE 4629) and became the industry standard for production data analysis within a few years of publication. The key insight was combining the early transient type curves from Aronofsky and Jenkins (1954) with Arps' empirical decline equations into a single coherent theoretical framework that linked the physical reservoir parameters to the observed production decline behaviour. More than 40 years after publication, Fetkovich's type curves remain in active daily use by reservoir engineers worldwide as one of the most impactful analytical tools in petroleum engineering history.

Type Curves for Unconventional Reservoirs

Conventional Fetkovich type curves assume radial flow in a homogeneous reservoir, which is not the flow geometry of hydraulically fractured tight oil or gas wells. These wells exhibit linear flow (fluid moving perpendicular to the fracture plane) during most of their productive life, and the flow regime transitions differently from the radial model. Specialised type curves have been developed for hydraulically fractured wells in tight reservoirs, including the Wattenbarger type curves for linear flow to a finite-conductivity fracture and the Blasingame-type flowing material balance method that handles variable-rate, variable-pressure history. For multi-stage fractured horizontal wells in resource plays, type curves with a stimulated reservoir volume (SRV) model — treating the fractured volume as an enhanced permeability zone around the horizontal lateral — provide EUR projections that account for the geometry of modern horizontal completions. These unconventional type curves are incorporated into commercial production analysis software (IHS Harmony, Kappa Ecrin, Fekete FAST RTA) used for daily reserve estimation.

Tip: When conducting type curve analysis on a tight gas or tight oil horizontal well, ensure that the analysis covers a sufficient time period to see the transition from linear flow to boundary-dominated flow. Type curve matching on data that has not yet shown boundary effects will produce highly uncertain EUR estimates because the well may still be in transient flow with no defined drainage area. The minimum recommended production history for type curve-based reserve estimation in most regulatory frameworks is one to three years of post-stimulation production, long enough to establish a reliable decline rate. Using early-time transient data alone for EUR extrapolation routinely overestimates reserves by 30-100% in tight reservoirs.

Type curve analysis is also referenced as:

Production data analysis (PDA) — the broader category encompassing type curve matching, flowing material balance, and rate-transient analysis; used when discussing the full suite of methods for extracting reservoir properties from production history
Rate transient analysis (RTA) — the modern term for the combined analysis of rate and pressure production data using type curves and analytical models; RTA is the preferred term in current SPE literature and captures the same methodologies as traditional type curve analysis
Decline curve analysis (DCA) — a related but distinct method that fits empirical decline equations (exponential, hyperbolic, harmonic) to production history for EUR estimation without the explicit reservoir physics of type curve matching; DCA is simpler but provides less reservoir diagnostic information than type curve analysis

Frequently Asked Questions

What is the difference between type curve analysis and decline curve analysis?

Both methods use production history to estimate reserves and well performance, but they differ fundamentally in their theoretical basis and information content. Decline curve analysis fits empirical mathematical equations (Arps exponential, hyperbolic, or harmonic decline) to observed production rate versus time without any physical model of reservoir flow. It provides EUR estimates but no reservoir property information (permeability, drainage area, skin). Type curve analysis uses solutions of the reservoir flow equation — grounded in Darcy's law and the diffusivity equation — to match production data to physically meaningful models. A successful type curve match yields permeability-thickness, skin factor, drainage area, and ultimate recovery, not just the EUR. The tradeoff is that type curve analysis requires both rate and flowing pressure data and a proper understanding of the well's flow regime history, while decline curve analysis needs only the rate history. For resource play wells where only production rate data is available and pressure is not measured, decline curve analysis remains the practical choice despite its lack of physical grounding.

How do you know when a well has reached boundary-dominated flow?

Boundary-dominated flow (BDF) occurs when the pressure transient from the wellbore has reached all boundaries of the drainage area and the well begins to deplete its finite reservoir volume rather than expanding its drainage radius. On a rate-time log-log plot, BDF appears as a definitive exponential decline (constant fractional rate of change) after the initial transient decline. On a flowing material balance plot (rate divided by pressure drop versus cumulative production), BDF appears as a straight line whose slope is inversely proportional to the drainage volume. In practice, BDF onset time depends on drainage area and permeability: a 100 mD conventional reservoir may reach BDF within weeks, while a 0.01 mD tight gas well may take years to reach BDF. For most unconventional wells in the first three to five years of production, the well is still in transient or transitional flow, and apparent type curve matches to BDF-based EUR models may significantly overestimate total reserves.

Why Type Curve Analysis Matters in Oil and Gas

The monetisation of oil and gas reserves depends on reliable estimates of how much oil or gas a well will ultimately produce and at what rate it will produce over its life. These estimates determine whether a development project receives investment approval, what price a producing property commands in a transaction, and what reserves a public company books on its balance sheet for SEC reporting. Type curve analysis is the primary method by which engineers extract this critical information from the production data that is the most abundant and economical data source available. In the era of unconventional tight oil and gas development, where hundreds of thousands of wells have been drilled with minimal pressure testing and where EUR estimation from multi-stage fractured horizontal wells remains technically challenging, type curve analysis and its modern successors (rate transient analysis) are the tools that make it possible to estimate reserves at scale from production history alone.