Type Curves: Well Test Analysis and Reservoir Characterization
What Are Type Curves?
Type curves are families of dimensionless pressure-change and pressure-derivative solutions computed from analytical reservoir models, plotted on log-log scales so interpreters can overlay field transient test data, match the characteristic shapes of flow regimes, and extract reservoir properties including permeability-thickness product and mechanical skin. They underpin modern well test interpretation across every producing basin from the Permian to the Norwegian Continental Shelf.
Key Takeaways
- Type curves express wellbore pressure response as dimensionless variables (PD, tD/CD) so that a single family of curves can represent any reservoir, fluid, or depth, enabling direct comparison between field data from a Montney tight gas well and a Saudi Arabia HPHT carbonate using the same diagnostic plot.
- The Bourdet pressure derivative (dP/d(ln t) = t × dP/dt), introduced in 1983, is the single most important advance in well test analysis: it stabilizes noisy data, amplifies subtle flow-regime transitions, and allows interpreters to identify radial flow (flat derivative), linear flow (half-unit slope), bilinear flow (quarter-unit slope), and boundary effects (upturn) on the same log-log plot.
- Matching field data to the Gringarten-Bourdet CDe2S type curve families simultaneously yields wellbore storage coefficient (C), skin (S), and the permeability-thickness product (kh), reducing ambiguity that plagued earlier semilog Horner analysis.
- In unconventional reservoirs, normalized-rate type curves derived from Palacio-Blasingame flowing material balance analysis and the Blasingame decline type curve family extend the concept to production data, enabling reserve estimation and completion benchmarking without a formal pressure buildup test.
- Regulatory bodies including Alberta's AER, the US offshore BSEE, Australia's NOPSEMA, and Norway's Sodir require pressure transient data submission for well deliverability assessments, resource certification, and reservoir management plans, making type curve analysis a legal reporting tool as well as an engineering discipline.
How Type Curve Analysis Works
A pressure transient test records bottomhole pressure and flow rate as functions of time, either during a drawdown (producing well) or a buildup (shut-in after production). The raw pressure data are processed into two diagnostic curves: the pressure change (delta-P, units of PSI or kPa) and the Bourdet derivative (dP/d(ln Δt), same units), both plotted against elapsed time on a log-log scale. This simultaneous display of delta-P and its derivative is called the diagnostic plot or log-log plot, and it is the first thing every well test interpreter examines. The pressure change alone often hides subtle flow regime transitions, but the derivative magnifies them: a flat derivative over at least one log cycle confirms radial flow and allows direct calculation of kh from the Ramey or Gringarten equations; a half-unit slope on the derivative indicates linear flow into a hydraulic fracture or along a narrow channel; a quarter-unit slope indicates bilinear flow in a fracture with finite conductivity; a unit slope on both curves simultaneously confirms wellbore storage, where production is entirely sustained by fluid expansion in the wellbore rather than reservoir influx.
Once the diagnostic plot is constructed, the interpreter selects a type curve family matching the expected well geometry. For a vertical well in a homogeneous reservoir, the Gringarten-Bourdet CDe2S families (also called the standard Bourdet type curves) provide a set of dimensionless pressure-derivative pairs parameterized by the product CDe2S, where CD is the dimensionless wellbore storage coefficient and S is the skin factor. The interpreter overlays the field log-log plot on the type curve sheet, sliding the data horizontally and vertically until the shape of the field curve matches a specific type curve member. The horizontal and vertical shifts between the data and the dimensionless axes provide the match-point coordinates that, combined with fluid properties (viscosity, formation volume factor) and wellbore geometry, yield the permeability-thickness product (kh, in millidarcy-feet or millidarcy-meters) and the skin factor (S, dimensionless). In modern software including Kappa Engineering's Saphir, IHS Harmony (now Enverus Harmony), Ecrin, and IQHP, the matching is performed by automated non-linear least-squares minimization, though experienced interpreters always review the automated solution visually.
Specialized type curves exist for every common well geometry and reservoir model. The Warren-Root dual-porosity type curves capture the characteristic trough-and-recovery signature of naturally fractured carbonates, where fluid first drains out of the fracture network (early radial flow) before matrix blocks begin feeding the fractures (transition period) and a second radial flow develops. Layered reservoir type curves (commingled multilayer) handle stratified sandstone sequences. Horizontal well type curves reveal the early vertical radial flow, linear flow phase, and late pseudo-radial flow transition unique to long horizontal laterals. Hydraulically fractured well type curves, developed by Gringarten, Ramey, and Raghavan in 1974 for infinitely conductive fractures and extended by Cinco-Ley and Samaniego in 1978 for finite-conductivity fractures, are essential for hydraulic fracturing diagnostics in the Montney, Duvernay, Haynesville, and Permian.
Type Curves Across International Jurisdictions
In Canada, the Alberta Energy Regulator (AER) governs well testing under Directive 040 (Pressure and Deliverability Testing of Oil and Gas Wells). Operators must submit test data, well histories, and interpretation reports for all test types, including pressure buildup (PBU), drawdown, and isochronal tests. The AER uses submitted type curve analyses as primary evidence in reserve determinations under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Montney and Duvernay tight gas wells in northeastern British Columbia operate under the BC Energy Regulator (BCER), which mandates analogous reporting under the B.C. Oil and Gas Commission's Operations Regulations. The extreme heterogeneity of the Montney siltstones, with permeabilities typically between 0.0001 and 0.01 millidarcy (0.0001 to 0.01 mD), means that flowing material balance and normalized-rate decline type curves from Enverus Harmony are used more frequently than conventional pressure buildup analysis, since shut-in times of weeks or months are required for pressure stabilization in rocks that tight.
In the United States, the Bureau of Safety and Environmental Enforcement (BSEE) requires pressure buildup tests and deliverability tests on all offshore wells in the Gulf of Mexico under 30 CFR Part 250, Subpart J. Onshore, the Railroad Commission of Texas (RRC) requires well tests for tight oil and gas wells seeking enhanced recovery permits, and the North Dakota Industrial Commission (NDIC) uses type curve benchmarks to certify proved developed reserves in Bakken Shale applications. The Permian Basin presents particular type curve challenges because prolific wellbore storage in deep, high-temperature wells (bottomhole temperatures of 200 to 280 degrees Fahrenheit, 93 to 138 degrees Celsius) can mask radial flow for several days, requiring deconvolution algorithms or multi-rate analysis to extract kh from production data. ExxonMobil, Pioneer, and ConocoPhillips publish Permian type curve benchmarks in investor presentations, but these production-based EUR type curves use normalized rate per foot of lateral and differ conceptually from classical pressure-transient type curves.
In Australia, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates well testing in Commonwealth waters under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 and the NOPSEMA Well Integrity Guidelines. Operators submit pressure transient data for all exploration and appraisal wells. The Cooper Basin in South Australia and Queensland, Australia's dominant onshore gas province, uses conventional pressure buildup analysis under state regulatory frameworks administered by the South Australian Department for Energy and Mining and the Queensland Resources Council. Cooper Basin tight gas reservoirs, particularly the Permian Patchawarra Formation, require wellbore storage correction and dual-porosity type curves in some naturally fractured intervals.
In Norway, the Norwegian Offshore Directorate (Sodir, formerly NPD) requires well test reporting for all exploration and production wells on the Norwegian Continental Shelf (NCS). Operators upload pressure transient data and interpretation reports to the Sodir FactPages database within 90 days of well completion. The NCS's prolific chalk reservoirs in the Ekofisk and Valhall fields require dual-porosity type curves, as the chalk matrix has very low permeability but naturally fractured networks of high conductivity. The Johan Sverdrup field in the North Sea, operated by Equinor, uses advanced type curve analysis for reservoir characterization of its Jurassic sandstones, where heterogeneous permeability ranging from 0.1 to 10 Darcy requires composite and layered type curve families to match buildup transients accurately.
In Saudi Arabia, Saudi Aramco operates some of the world's most challenging high-pressure, high-temperature (HPHT) reservoirs, including the Arab-D carbonate at Ghawar where reservoir temperatures exceed 120 degrees Celsius (248 degrees Fahrenheit) and pressures exceed 300 bar (4,351 PSI). Aramco employs custom HPHT pressure gauges capable of operating continuously at temperatures above 150 degrees Celsius (302 degrees Fahrenheit), which is near or above the rated maximum for conventional quartz crystal gauges. Type curve matching in these conditions requires temperature-corrected fluid property tables and HPHT-calibrated wellbore storage models, since fluid compressibility and viscosity change significantly with temperature in carbonate brines. Aramco's Jafurah unconventional gas development, targeting the Lower Jurassic tight carbonates and siltstones at depths of 3,000 to 5,000 m (9,843 to 16,404 ft), adapts North American unconventional type curve methods to HPHT conditions.
Fast Facts
The concept of type curves in well test analysis was formally introduced by Henry J. Ramey Jr. at Stanford University in his landmark 1970 SPE paper "Short-Time Well Test Data Interpretation in the Presence of Skin Effect and Wellbore Storage." Ramey recognized that plotting dimensionless pressure against dimensionless time on log-log scales made all wells dimensionless, collapsing thousands of possible reservoir and fluid combinations onto a finite number of curve families. Within a decade, the McKinley curves (1974), the Gringarten-Ramey-Raghavan fracture curves (1974), and the Bourdet derivative (1983) had transformed well test interpretation from an art requiring experienced intuition into a systematic engineering discipline with quantitative uncertainty bounds.