Typical Decline Curve Parameters by Basin & Play
Reference table of typical Arps decline parameters for major US unconventional oil and gas plays. Based on publicly available data from state regulatory commissions, EIA reports, and industry publications (2018–2024 vintage wells).
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Oil & Condensate Plays
Typical parameters for horizontal wells with modern completions (2018–2024 vintage). Ranges reflect P10–P90 across operators.
| Basin / Play | Type | qi (bbl/d) | Di (annual) | b-factor | EUR (MBO) | IP30 (bbl/d) | Vintage Notes |
|---|---|---|---|---|---|---|---|
| Permian — Wolfcamp A | Oil | 800 – 1,200 | 0.60 – 0.90 | 1.0 – 1.5 | 400 – 700 | 600 – 950 | Delaware & Midland sub-basins; 7,500–10,000 ft laterals; 2020–2024 |
| Permian — Wolfcamp B | Oil | 600 – 1,000 | 0.55 – 0.85 | 1.0 – 1.4 | 350 – 600 | 500 – 800 | Generally lower EUR than Wolfcamp A; thicker pay in some areas; 2019–2024 |
| Permian — Bone Spring | Oil | 700 – 1,100 | 0.65 – 0.95 | 0.9 – 1.4 | 300 – 550 | 550 – 850 | Delaware Basin focus; 2nd/3rd Bone Spring sands; 2019–2024 |
| Permian — Spraberry | Oil | 400 – 800 | 0.50 – 0.80 | 1.0 – 1.5 | 250 – 500 | 350 – 650 | Midland Basin; lower IPs but shallower wells & lower cost; 2018–2024 |
| Bakken / Three Forks | Oil | 500 – 900 | 0.50 – 0.80 | 1.0 – 1.4 | 300 – 600 | 400 – 750 | NDIC data; Williston Basin core areas (McKenzie, Mountrail, Dunn cos.); 2019–2024 |
| Eagle Ford — Oil Window | Oil | 600 – 1,000 | 0.70 – 1.00 | 0.8 – 1.3 | 250 – 500 | 500 – 800 | RRC TX data; Karnes, DeWitt, Gonzales cos.; steeper early decline; 2019–2024 |
| Eagle Ford — Condensate | Cond. | 400 – 700 | 0.60 – 0.90 | 0.9 – 1.3 | 200 – 400 | 350 – 600 | Condensate window; high GOR; liquid yield varies with pressure; 2019–2024 |
| DJ Basin — Niobrara | Oil | 400 – 800 | 0.55 – 0.85 | 1.0 – 1.5 | 250 – 450 | 350 – 650 | COGCC data; Wattenberg Field & surrounding; A/B/C benches; 2019–2024 |
| SCOOP / STACK | Oil | 500 – 900 | 0.55 – 0.85 | 0.9 – 1.4 | 250 – 500 | 400 – 700 | OCC data; Woodford & Meramec targets; Canadian, Blaine, Grady cos.; 2019–2024 |
| Uinta Basin | Oil | 300 – 700 | 0.45 – 0.75 | 1.0 – 1.6 | 200 – 450 | 250 – 550 | DOGM data; waxy crude; emerging horizontal development; 2020–2024 |
Dry Gas & Wet Gas Plays
Parameters in gas units (Mcf/d, Bcf). EUR reflects estimated ultimate recovery of raw gas.
| Basin / Play | Type | qi (Mcf/d) | Di (annual) | b-factor | EUR (Bcf) | IP30 (Mcf/d) | Vintage Notes |
|---|---|---|---|---|---|---|---|
| Eagle Ford — Gas Window | Gas | 5,000 – 12,000 | 0.65 – 0.95 | 0.8 – 1.2 | 3.0 – 8.0 | 4,000 – 10,000 | RRC TX; Webb & Dimmit cos. dry gas window; 2019–2024 |
| Marcellus Shale | Gas | 8,000 – 20,000 | 0.55 – 0.80 | 1.0 – 1.6 | 8.0 – 20.0 | 6,000 – 16,000 | PA DEP & WV DEP data; NE PA dry gas & SW PA wet gas; 2019–2024 |
| Haynesville Shale | Gas | 10,000 – 25,000 | 0.70 – 1.00 | 0.8 – 1.3 | 6.0 – 16.0 | 8,000 – 20,000 | SONRIS data; high IP / steep decline; 15,000+ ft laterals common; 2020–2024 |
| Appalachian — Utica / Point Pleasant | Gas | 6,000 – 18,000 | 0.55 – 0.85 | 1.0 – 1.5 | 5.0 – 15.0 | 5,000 – 14,000 | ODNR & WV DEP data; dry gas, wet gas, and condensate windows; 2019–2024 |
Key Observations Across Basins
Permian Basin dominates oil EUR
Wolfcamp A wells in the Delaware sub-basin consistently deliver the highest oil EURs among US unconventional plays, driven by thick pay zones, high porosity, and increasingly efficient completions. Lateral lengths have stretched beyond 10,000 ft in many new wells, pushing EUR/well even higher while reducing per-BOE costs.
Marcellus leads gas EUR
The Marcellus Shale in NE Pennsylvania produces the highest per-well gas EURs in North America. Low decline rates (high b-factors of 1.0–1.6) combined with enormous IPs from overpressured zones result in individual wells that can recover 15–20+ Bcf over their productive life.
Haynesville: high IP, steep decline
Haynesville wells exhibit the highest initial production rates among gas plays but also the steepest first-year declines (Di of 0.70–1.00). The lower b-factor (0.8–1.3) means these wells transition to exponential decline more quickly, which is critical to model correctly for reserve bookings.
Eagle Ford: three distinct windows
The Eagle Ford spans oil, condensate, and dry gas windows with materially different decline characteristics. Oil-window wells show steeper initial decline (Di up to 1.0/yr) but lower b-factors, while gas-window wells maintain higher rates longer. Lumping all Eagle Ford wells together will produce misleading type curves.
What Do These Parameters Mean?
qi — Initial Production Rate
The production rate at time zero in the Arps decline model. In practice, qi is often taken as the peak 24-hour rate or the first full month's average daily rate after flowback cleanup. It is the single most visible metric operators report, but it can be misleading without the corresponding decline parameters. A well with high qi but steep decline may recover less oil than a moderate-IP well with a flatter profile. Units are barrels per day (bbl/d) for oil or thousand cubic feet per day (Mcf/d) for gas.
Di — Initial Decline Rate
The nominal decline rate at time zero, expressed on an annual basis. A Di of 0.80 means the well's production is declining at 80% per year at the start (before the b-factor slows it down). In the Arps hyperbolic equation q(t) = qi / (1 + b · Di · t)1/b, Di controls how fast production drops in the first months. Higher Di values are typical in overpressured plays (Haynesville, Eagle Ford) where rapid drawdown dominates early production. Lower Di values appear in plays with stronger aquifer support or more gradual depletion.
b-factor (Arps Exponent)
The Arps decline exponent controls how rapidly the decline rate itself declines over time. A b of 0 gives exponential decline (constant decline rate), b of 1 gives harmonic decline, and values between 0 and 1 give hyperbolic decline. In unconventional wells, b-factors routinely exceed 1.0 during the transient flow period, which is why direct application of Arps to early-life data often overestimates EUR. Typical b-factors of 1.0–1.6 for shale wells reflect this transient behavior. As boundary-dominated flow develops (often years into production), the effective b-factor drops toward 0.3–0.5. Proper forecasting requires either switching to exponential terminal decline (Dmin) or using a stretched exponential model.
EUR — Estimated Ultimate Recovery
The total cumulative production a well is expected to deliver over its economic life, expressed in thousands of barrels of oil (MBO) or billion cubic feet of gas (Bcf). EUR depends heavily on the decline model used, the assumed economic limit rate, and the terminal decline rate. Small changes in b-factor or Dmin can shift EUR by 20–40%, which is why the SEC requires proved reserves to be based on reliable production trends, not early-time extrapolations.
IP30 — 30-Day Initial Production
The average daily production rate over the first 30 calendar days of production. IP30 is a more stable metric than peak 24-hour IP because it smooths out flowback effects, choke management, and facility constraints. It is commonly used by operators in investor presentations and is the basis for most public type curve comparisons. IP30 is always lower than qi because it averages over the early steep decline period.
Why Parameters Vary by Play
Decline curve parameters are not arbitrary numbers — they reflect the underlying reservoir physics and completion design of each play. Several factors drive the differences you see in the table above:
- Reservoir pressure and permeability: Overpressured plays like the Haynesville (0.9+ psi/ft gradient) deliver enormous initial rates but deplete faster, yielding high qi and high Di. Normally pressured plays like the Spraberry show more moderate IPs but flatter declines.
- Rock quality and thickness: The Wolfcamp A in the Delaware Basin has 200–500 ft of net pay across multiple landing zones, directly translating to higher EUR per well. Thinner targets like the Bone Spring 2nd sand show more constrained recovery.
- Completion intensity: More proppant per lateral foot (2,000–3,000 lb/ft) and tighter cluster spacing (15–30 ft) increase qi and IP30 but may steepen decline if they accelerate depletion without proportionally increasing drainage area.
- Lateral length: Modern laterals range from 5,000 ft (short Permian infills) to 15,000+ ft (Haynesville, Marcellus). Longer laterals increase qi and EUR roughly proportionally, but the per-foot parameters remain similar. Always normalize to per-1,000-ft or per-lateral-foot when comparing.
- Fluid type and GOR: Oil wells generally show steeper early decline than gas wells because oil mobility is lower and solution gas drive weakens as pressure drops below bubble point. High-GOR condensate wells (Eagle Ford condensate window) have intermediate behavior.
- Parent-child effects: Infill (child) wells drilled near existing producers typically underperform parent wells by 15–30% due to pressure depletion and frac hits. Type curves built on parent-well data will overpredict child-well performance.
Arps Hyperbolic vs. Stretched Exponential (SEPD)
The Arps hyperbolic model (1945) is the industry workhorse for decline curve analysis because it is simple, well-understood, and anchored in decades of practice. However, it has a well-known limitation in unconventional wells: when b > 1, the hyperbolic model predicts infinite cumulative production as time approaches infinity. This is physically impossible.
In practice, engineers handle this by imposing a minimum decline rate (Dmin), typically 5–8% per year, at which point the forecast switches from hyperbolic to exponential terminal decline. This "modified hyperbolic" approach works well for PDP (proved developed producing) reserves but requires judgment in selecting Dmin.
The Stretched Exponential Production Decline (SEPD) model, introduced by Valko and Lee (2010), avoids this problem entirely. It uses three parameters (qi, tau, and n) and inherently converges to a finite EUR without requiring a Dmin assumption. The SEPD model tends to produce more conservative (and often more accurate) long-term forecasts for unconventional wells.
When to use each model
Use Arps (Modified Hyperbolic) When:
- Preparing SEC reserve reports (industry standard)
- Benchmarking against published type curves
- Quick screening of acquisition targets
- Wells with 12+ months of production history showing clear b-factor stabilization
- Communicating with investors, banks, or partners who expect Arps parameters
Use SEPD When:
- Early-time forecasts with <6 months of data
- Comparing model robustness (SEPD vs. Arps as a sanity check)
- Wells with transient flow dominating (high apparent b-factor)
- Internal planning where you want conservative EUR estimates
- Probabilistic forecasting (SEPD parameters lend themselves to Monte Carlo sampling)
How to Use These Parameters for Screening
These parameters are intended as screening-level references, not substitutes for well-specific decline curve analysis. Here is how to use them effectively:
- Benchmark your wells: Compare your actual well performance against the basin/play ranges. If your wells are below the P10 end of these ranges, investigate completion design, reservoir quality, or operational issues. If above P90, verify your data before celebrating.
- Screen acquisitions: When evaluating an A&D package, use these ranges as a sanity check on the seller's type curves. If their projected EUR is 2x the top of the range for their play, demand detailed justification.
- Initial economic screening: Plug the midpoint values into a well economics calculator to estimate NPV, breakeven price, and payout at current commodity prices before committing to detailed analysis.
- Normalize before comparing: These ranges assume typical modern lateral lengths (7,500–10,000 ft for Permian; 10,000–15,000 ft for Haynesville/Marcellus). Normalize to per-1,000-ft when comparing wells with different lateral lengths.
- Account for vintage: Well performance has improved significantly vintage-over-vintage due to longer laterals, more sand, and tighter spacing. Wells drilled in 2018 may look 20–30% worse than 2023 completions in the same area.
For well-specific analysis, use our AI Decline Curve Analyzer to fit your actual production data and generate a detailed forecast.
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Data Sources & Methodology
Parameters are compiled from publicly available sources and represent typical ranges for horizontal wells with modern completions (2018–2024 vintage):
- Permian Basin: Texas Railroad Commission (RRC) production data, New Mexico OCD well records
- Bakken: North Dakota Industrial Commission (NDIC) monthly production reports
- Eagle Ford: Texas Railroad Commission (RRC) well completion and production data
- Marcellus & Utica: Pennsylvania DEP, West Virginia DEP, Ohio DNR production reports
- Haynesville: Louisiana SONRIS (Strategic Online Natural Resources Information System)
- DJ Basin: Colorado Oil and Gas Conservation Commission (COGCC) production data
- SCOOP/STACK: Oklahoma Corporation Commission (OCC) well data
- Uinta: Utah Division of Oil, Gas, and Mining (DOGM) production records
- General: EIA Drilling Productivity Reports, Enverus/DrillingInfo public presentations, SPE/URTeC published papers
Ranges reflect approximately P10–P90 spread across operators and acreage positions within each play. Individual well results may fall outside these ranges depending on specific location, completion design, lateral length, and reservoir quality. Always verify against operator-specific type curves when available.