NSLLC Toolkit
Unit Converter
Water Viscosity (McCain, 1990)
@ 1 atm
μw = — cp
μw = A·T^B, A & B are polynomials in salinity (wt%). Valid ~100–400°F, 0–26 wt%.
Hydrostatic Pressure
Pressure = — psi |
Gradient = — psi/ft
P (psi) = 0.052 × MW (ppg) × TVD (ft)
API Gravity ↔ Specific Gravity
SG = 141.5 / (131.5 + °API). Edits in either field update the other.
Gas Formation Volume Factor (Bg)
Bg = — ft³/scf |
— rb/scf
Bg = 0.02827 · Z · T(°R) / P(psia); 1 rb = 5.615 ft³
Oil Formation Volume Factor (Bo, Standing 1947)
Bo = — rb/STB
Bo = 0.972 + 0.000147 · F^1.175, F = Rs·√(γg/γo) + 1.25·T(°F); γo from °API. Valid for saturated oil near bubble point.
Dead Oil Viscosity (Beggs & Robinson, 1975)
Estimate gas-free (dead) crude oil viscosity from stock-tank API gravity and reservoir temperature — the standard screening correlation when a measured viscosity is unavailable. The result is the dead-oil viscosity μod; live-oil viscosity at reservoir conditions is lower and requires solution gas-oil ratio (see methods note).
1. Inputs
Stock-tank oil gravity at 60°F. The Beggs-Robinson dead-oil fit was developed over roughly
16 to 58 °API; extrapolation below ~10 °API (heavy/biodegraded California crudes) grows
uncertain and tends to underpredict viscosity. Related to specific gravity by
SG = 141.5 / (131.5 + °API).
Temperature at which the viscosity is wanted — reservoir temperature for in-situ mobility,
or a shallower value for wellbore or surface conditions. Viscosity falls steeply as
temperature rises, so this input dominates the result.
Auto uses Beggs-Robinson at or above 16 °API and Egbogah-Ng (its heavy-oil extension) below
16 °API, so any gravity returns a defensible estimate. For heavy and extra-heavy crudes
(roughly 6-15 °API) Egbogah-Ng is valid where Beggs-Robinson is an extrapolation. The active
correlation and its range are shown with the result. Below ~5 °API both are extrapolations —
prefer a measured viscosity-temperature curve.
2. Result
—
—
—
Dead oil viscosity, μod
—
—
Correlation used
—
—
—
—
intermediate
Specific gravity, γo
—
141.5 / (131.5 + °API)
Methods, references, and caveats
- Correlation selection: Auto applies Beggs-Robinson at or above 16 °API and Egbogah-Ng below 16 °API; either can be forced. Both give dead-oil (gas-free) viscosity in cP with T in °F. The active correlation and its valid range travel with the result and the citation.
- Beggs and Robinson (1975): μod = 10x − 1, x = y·T−1.163, y = 10z, z = 3.0324 − 0.02023·°API. Fit to 460 dead-oil observations spanning roughly 16-58 °API and 70-295°F. Accuracy degrades outside the fitted range, particularly for heavy oils.
- Egbogah-Ng (1983), "modified Beggs-Robinson": log10[log10(μod + 1)] = 1.8653 − 0.025086·°API − 0.5644·log10(T), T in °F. Recalibrated on ~400 samples extending to lower gravity; applicable roughly 5-50 °API and 60-300°F, and the recommended choice for heavy and extra-heavy crude where Beggs-Robinson is an extrapolation. Reference: Egbogah, E.O. and Ng, J.T. (1990), "An improved temperature-viscosity correlation for crude oil systems," Journal of Petroleum Science and Engineering, vol. 4, no. 3, pp. 197-200 (correlation first presented by Egbogah, PETSOC 83-34-32, 1983).
- Extra-heavy oils (°API ≤ 10): De Ghetto et al. (1995), "Pressure-Volume-Temperature Correlations for Heavy and Extra Heavy Oils" (SPE International Heavy Oil Symposium), recalibrated the modified-Egbogah form separately for heavy (10 < °API ≤ 22.3) and extra-heavy (°API ≤ 10) oils and is the most targeted published correlation for that range. It is not implemented here pending verification of the published coefficients from the primary source; for °API ≤ 10, treat the Egbogah-Ng result as a screening estimate and prefer measured viscosity.
- Dead vs. live oil: with the toggle off, the result is the gas-free (dead) viscosity. Toggle on and enter solution GOR to get the live (saturated) viscosity at reservoir pressure, which is lower. The live-oil relation is μob = A·μodB, where A = 10.715·(Rs + 100)−0.515 and B = 5.44·(Rs + 150)−0.338, with Rs the solution gas-oil ratio (scf/STB).
- Saturated vs. undersaturated: the live-oil relation applies at or below the bubble-point pressure. Above the bubble point (undersaturated), viscosity increases with pressure and the Vasquez-Beggs undersaturated correction μ = μob·(P/Pb)m should be applied — not included here.
- Alternative dead-oil correlations: Beal (1946) and Glaso (1980) are the common alternatives. Beal tends to run higher at low temperature; Glaso was fit to North Sea crudes. Beggs-Robinson is the most widely used default for screening.
- Heavy California crudes: for biodegraded heavy oils common in shallow California fields, use Egbogah-Ng (Auto does this below 16 °API). Even so, dead-oil viscosity for such crudes is highly variable and correlations can scatter by an order of magnitude; prefer a measured viscosity-temperature curve (e.g., ASTM D7042 / D445) where available and use the correlation as a cross-check.
- Screening use: intended as a defensible first estimate. For mobility ratio, injectivity, or reserves work where viscosity is a sensitive input, corroborate with laboratory PVT data.
Cement Volume (Annular)
Annular = — bbl (— ft³) |
With excess = — bbl
Sacks = — sk |
Mix water = — bbl |
Displacement = — bbl
Annular bbl/ft = (Dh² − OD²)/1029.4; Internal bbl/ft = ID²/1029.4. Sacks = annular ft³·(1+excess)/yield. Defaults are typical Class H neat.
Original Oil in Place (Volumetric)
OOIP = — STB |
— MMSTB
Recoverable = — STB |
— MMSTB
N = 7758 · A · h · NG · ϕ · (1−Sw) / Boi (7758 bbl per acre-ft). Recoverable = N · RF.
Original Gas in Place (Volumetric)
OGIP = — scf |
— Bcf
G = 43,560 · A · h · NG · ϕ · (1−Sw) / Bgi (43,560 ft³ per acre-ft). 1 Bcf = 10⁹ scf.
BOE Converter
BOE = Mcf / ratio. 6:1 is the SEC/energy-equivalence standard; some operators use 20:1 for current-price economic equivalence.
Arps Decline (Forecast & EUR)
—
Rate (bbl/d) vs t (yr)
Cum Np (bbl) vs t (yr)
EUR
—
bbl
EUR
—
MMSTB
Economic life
—
yr
qfinal
—
bbl/d
Exp (b=0): q=qi·exp(−Dit). Hyp: q=qi/(1+b·Dit)1/b. Harm (b=1): q=qi/(1+Dit). With Dmin: switches to exponential at Dmin when instantaneous D(t) reaches it.
Single-Well Economics
Uses the Arps annual production above. CAPEX hits at t=0; abandonment hits at the last positive-CF year. Revenue scales on RI (operator share of revenue). OPEX, CAPEX, and abandonment scale on WI (operator share of cost). Dollar outputs are in $M (thousands, petroleum convention).
Pricing & production
Operating & capital costs (WI basis)
Ownership
Results
Gross oil
—
bbl
Net oil to RI
—
bbl
Gross gas EUR
—
MMcf
Net gas to RI
—
MMcf
Oil revenue
—
$M
Gas revenue
—
$M
Total OPEX (WI)
—
$M
Peak cash exposure
—
$M
Undisc net CF
—
$M
NPV @ disc rate
—
$M
Payout
—
yr
Break-even oil
—
$/bbl
IRR
—
%
MOIC
—
x
ROI (undisc)
—
PHDWin
ROI (disc)
—
PHDWin
Economic life = — yr
(terminated by —; q at term = — bbl/d)
NPV Profile ($M)
Oil Price Sensitivity
Sensitivity to flat oil price. All other inputs held constant. Current price column is highlighted.
Per year: Oil rev = RI · Qoil · Poil; Gas rev = RI · (Qoil·GOR/1000) · Pgas;
OPEX = WI · (12·Fixed·Δt + Qoil · Variable); CF = Oil rev + Gas rev − OPEX.
Cash-out at t=0: −WI·CAPEX. NPV = −WI·CAPEX + Σ CFy/(1+d)y.
Project life ends at the earlier of (a) qecon rate floor or (b) last year where rev − opex > 0;
abandonment is booked on that final year. Break-even oil holds gas price, GOR, ownership, and economic life fixed.
Gas is treated as associated production via constant GOR with no incremental OPEX. ROI follows PHDWin
convention: ROIundisc = cumCF / (WI·CAPEX), ROIdisc = NPV / (WI·CAPEX).
Default RI = WI × Lease NRI / 100; override for carries, ORRIs, or non-standard arrangements.
CO₂ Mass ↔ Volume Conversions
Enter any value; all others update. Reservoir-condition volumes use the editable density below.
Mass
Standard volume (60°F, 14.696 psia)
Reservoir-condition volume (uses ρ above)
Basis — CO₂ MW: 44.01 g/mol; std density: 0.1144 lb/scf (≈ 1.842 kg/sm³);
1 tonne ≈ 19,252 scf; 1 sm³ = 35.315 scf. Reservoir volume = mass / ρres.
CO₂ Density, Viscosity & Phase
Enter pressure and temperature at reservoir conditions. Density via Peng-Robinson EOS; viscosity is a screening approximation (see method note). Phase diagram below updates live with the inputs — the red marker is your point.
ρ = — g/cc |
— lb/ft³ |
— kg/m³
μ = — cP |
Phase: —
Density: Peng-Robinson cubic EOS (Tc=304.13 K, Pc=7.377 MPa, ω=0.225). Valid 1000-5000 psi, 60-250°F.
Viscosity: density-based screening fit calibrated to NIST WebBook (~±10%). Use NIST for critical work.
Vaporization curve: Span & Wagner (1996); sublimation & fusion dashed. Y-axis log scale.
Storage Capacity (DOE/NETL Volumetric)
GCO₂ = A · h · ϕ · (1 − Swirr) · ρCO₂ · E. Per Goodman et al. (2011) / DOE-NETL Carbon Storage Atlas methodology.
Capacity = — tonnes |
— Mt |
— MMcf (std)
At — Mt/yr injection: — years
Typical E (Goodman et al. 2011 / DOE-NETL): saline aquifers 1–4%; depleted oil/gas reservoirs 5–20%.
Reservoir volume × density × E = stored mass. 1 tonne CO₂ ≈ 19,252 scf at standard conditions.
CO₂ Injection Rate Conversions
Enter any rate; all others update. Surface volumes at standard conditions; reservoir volumes use ρ below.
Mass rate
Standard volume rate (60°F, 14.696 psia)
Reservoir volume rate (uses ρ above)
Conversion basis as in Section 1. Mt/yr uses 365.25-day year. Reservoir m³ = mass / ρres.
Plume Radius (Volumetric Estimate)
Screening estimate assuming uniform radial displacement. Does NOT account for buoyancy, dissolution, residual trapping, or heterogeneity.
rplume = — ft |
— m
r = √[ (M / ρCO₂) / (π · h · ϕ · (1 − Swirr)) ]. Screening only.
Quick Reference Constants
CO₂ properties & conversion constants
- CO₂ critical point: 1071 psia, 87.98°F (31.1°C, 7.38 MPa)
- CO₂ triple point: 75.13 psia, −69.83°F (−56.57°C, 0.518 MPa)
- CO₂ molecular weight: 44.01 g/mol
- Standard density (60°F, 14.696 psia): 0.1144 lb/scf ≈ 1.842 kg/sm³
- 1 tonne CO₂ ≈ 19,252 scf at standard conditions
- 1 Mt CO₂ ≈ 19.25 Bscf at standard conditions
- Typical supercritical density at CCS conditions: 0.5–0.8 g/cc
- DOE storage efficiency E: 1–4% (saline), 5–20% (depleted HC) — Goodman et al. 2011
- 1 acre = 43,560 ft²; 1 acre-ft = 7,758 bbl = 43,560 ft³ ≈ 1,233 m³
Resistivity-Porosity Salinity Calculator
Petrophysical salinity estimate from log resistivity. Estimates formation water resistivity (Rw) from Rt and ϕ via a formation factor (F = Ro/Rw) relationship, corrects Rw to a reference temperature with Arps (1953), and converts to NaCl-equivalent salinity. Used for Class VI CCS and Class II UIC USDW characterization.
1. Temperature at depth
Surface T
—
°F
Gradient
—
°F/100 ft
T at target depth
—
°F
2. Base case inputs
3. Salinity correlation
Active: Gen-9
4. Rock type / formation factor
5. Base case results
Formation factor, F
—
—
Rw at depth T
—
ohm-m
Rw at Tref
—
ohm-m
NaCl salinity
—
ppm
Estimated TDS
—
ppm (NaCl-eq)
6. Implied Rt at reference salinities
Rt that would correspond to the indicated NaCl-equivalent salinity, holding ϕ, formation factor method, depth temperature, and Tref at their current values. 10,000 ppm is the USDW threshold (40 CFR §144.3); 3,000 ppm is a common Class VI confining-zone reference.
Rt @ 10,000 ppm NaCl
—
ohm-m
Rt @ 3,000 ppm NaCl
—
ohm-m
7. Sensitivity — NaCl (ppm) vs. ϕ and formation factor method
Rt, depth temperature, and Tref held constant. Active row (selected rock type) and active column (current ϕ rounded to nearest 5%) are tinted. Intersection cell is the base-case anchor. Active correlation: Gen-9.
8. Methods, references, and caveats
- Arps temperature correction: Rw(T2) = Rw(T1) · (T1 + 7) / (T2 + 7), T in °F. Arps (1953).
- Gen-9 NaCl (default): NaCl (ppm) = ROUND(5697.5 · Rw(Tref)−1.079, nearest 10). Empirical fit to the Schlumberger Gen-9 chart at Tref = 75°F.
- Schlumberger 1988 chart correlation: NaCl (ppm) = 10((3.562 − log10(Rw(Tref) − 0.0123)) / 0.955). From Schlumberger Log Interpretation Charts, 1988 edition, Gen-9.
- Archie's law: F = Ro/Rw; Rw = Rt/F under fully water-saturated, clean (shale-free) conditions. Hydrocarbon presence or shaliness will bias Rw high (and salinity low).
- Default surface T: 70°F (typical for shallow subsurface in coastal California). Adjust for site-specific MAGT (mean annual ground temperature).
- Default gradient (Mode B): 1.6°F/100 ft, representative of average California sedimentary-basin geothermal gradient. Local gradients range ~1.4–1.8°F/100 ft in non-geothermal basins, higher near the Coast Ranges and Salton Trough.
- TDS vs. NaCl-equivalent: reported salinity is NaCl-equivalent. For brines with significant Ca, Mg, sulfate, or bicarbonate, true TDS may differ materially. Apply ion-specific corrections if available.
- Shaly intervals: apply Waxman-Smits, dual-water, or Indonesia model separately. This calculator assumes clean-zone Archie analysis.
Workflow: F is computed from ϕ using the selected rock-type relationship → Rw at depth T = Rt/F →
Rw at Tref via Arps → NaCl via active correlation. All inputs are live; the sensitivity table
recomputes on every change.
Total Compressibility (ct)
Compute total reservoir compressibility ct = crock + Sw·cw + So·co for Class II UIC water injection. Provides a defensible, citation-backed input value for ZEI / AOR calculations. Standard practice per 40 CFR §146.6.
1. Component inputs
Water saturation in the injection zone. For a water-saturated disposal zone (typical Class II
injection into a brine aquifer or fully swept reservoir), Sw = 1.0. For a partially
depleted reservoir with residual oil, use the actual Sw from log analysis or core data.
Residual oil saturation in the injection zone. For a clean disposal zone, So = 0.
For a depleted producer being converted to injection, use the post-production residual
Sor — typically 0.20–0.35 depending on the formation.
Pore-volume compressibility of the reservoir rock. Typical values: 3–5 × 10⁻⁶ /psi for
consolidated sandstones, 4–7 × 10⁻⁶ /psi for unconsolidated sands (common in California
shallow disposal zones), 5–10 × 10⁻⁶ /psi for friable or poorly consolidated formations,
2–4 × 10⁻⁶ /psi for limestones, 3–6 × 10⁻⁶ /psi for dolomites. Default 4 × 10⁻⁶ /psi is
appropriate for typical consolidated sandstone. Reference: Newman (1973), "Pore-Volume
Compressibility of Consolidated, Friable, and Unconsolidated Reservoir Rocks Under
Hydrostatic Loading," JPT.
Compressibility of formation water at reservoir conditions. Typical range 2.5–3.5 × 10⁻⁶ /psi
for brines at 100–200°F and 1000–3000 psi. Increases slightly with temperature, decreases
slightly with pressure and salinity. Default 3 × 10⁻⁶ /psi is appropriate for typical produced
water. Reference: McCain (1990), The Properties of Petroleum Fluids, 2nd ed.
Compressibility of residual oil at reservoir conditions, above bubble point. Typical range
5–15 × 10⁻⁶ /psi depending on API gravity, GOR, and pressure. Lighter oils with higher GOR
have higher compressibility. Default 10 × 10⁻⁶ /psi is appropriate for typical California
heavy-to-medium crude. Reference: McCain (1990), Vasquez-Beggs correlation. Note: contributes
zero to ct when So = 0.
2. Reference table — typical compressibility values
| Component | Range (× 10⁻⁶ /psi) | Notes |
|---|---|---|
| Consolidated sandstone | 3 – 5 | Most California Miocene/Pliocene reservoirs |
| Unconsolidated sand | 4 – 7 | Shallow disposal zones, friable formations |
| Limestone | 2 – 4 | Lower porosity, stiffer matrix |
| Dolomite | 3 – 6 | Variable with fabric |
| Fresh water | 3.0 – 3.3 | At reservoir T and P |
| Produced water (saline) | 2.8 – 3.2 | Lower at higher salinity |
| Dead oil (low GOR) | 5 – 10 | Above bubble point |
| Live oil (high GOR) | 10 – 25 | Above bubble point |
3. Results
ct = crock + Sw × cw + So × co
—
—
Total compressibility, ct
—
—
Rock contribution
—
—
Water contribution (Sw·cw)
—
—
Oil contribution (So·co)
—
—
—
4. Methods, references, and caveats
- Total compressibility equation: ct = crock + Sw·cw + So·co. Saturation-weighted additive sum of pore-volume and fluid-phase isothermal compressibilities.
- Assumptions: gas saturation = 0 (typical Class II brine disposal); single-phase oil above bubble point; isothermal; component contributions independent and additive.
- Newman (1973): "Pore-Volume Compressibility of Consolidated, Friable, and Unconsolidated Reservoir Rocks Under Hydrostatic Loading," Journal of Petroleum Technology, February 1973. Source for crock ranges.
- McCain (1990): The Properties of Petroleum Fluids, 2nd ed., PennWell Books. Source for cw and co defaults; oil compressibility above bubble point per the Vasquez-Beggs correlation.
- Regulatory basis: standard practice for Class II UIC area-of-review (AOR) and zone of endangering influence (ZEI) calculations per 40 CFR §146.6.
- Pressure / temperature dependence: component compressibilities vary with reservoir conditions. Defaults assume 100–200°F, 1000–3000 psi (typical California shallow disposal zones). For significantly different conditions, adjust component values using published correlations.
- Below bubble point: oil compressibility rises sharply as dissolved gas evolves, and this simple additive model is no longer valid. Assume single-phase oil for ct purposes.
- High-salinity brines: for >100,000 ppm TDS, cw can fall below 2.5 × 10⁻⁶ /psi; apply a salinity-corrected value if needed.
Darcy Permeability (RAT)
Effective (skin-included) permeability from a stabilized single-rate injectivity test (RAT survey) on a Class II UIC well. Computes bottomhole flowing pressure from surface injection pressure accounting for hydrostatic head and tubing friction, then applies Darcy's steady-state radial flow equation.
1. Survey data
Wellhead injection pressure measured during the stabilized portion of the RAT survey.
Use the value paired with the observed rate, not a long-term average.
Instantaneous measured rate at the wellhead flowmeter during the stabilized portion of the
survey — not the monthly average from injection records. Use the rate paired with
the Psurf above. The well should have been injecting at this rate for at least
1–2 hours before the reading to ensure pressure has stabilized.
Reservoir temperature at the depth of interest. From BHT surveys, RAT temperature log, or
computed from geothermal gradient. Used to auto-compute water viscosity. Default 120°F is
typical for shallow California disposal zones.
Date of the RAT survey. Used in PDF/print reports only.
2. Well configuration
Measured depth from surface to the top of the perforated interval (length of the tubing
string). Used for both hydrostatic and friction calculations. For deviated wells, use
measured depth; for highly deviated wells, hydrostatic should ideally use TVD — a future
revision will support this.
Standard API tubing sizes. Selecting an OD/weight auto-fills the ID below. Choose "Custom"
for non-standard tubing.
Inside diameter of injection tubing. Auto-populates based on the tubing size selected above.
Override for non-standard or worn tubing.
Pipe surface roughness. Default 0.0018 in for new commercial steel tubing. Increase to
0.005–0.01 in for scaled, corroded, or service-aged tubing. The friction calculation is
moderately sensitive to roughness.
Radius of the wellbore at the perforations. Equals (hole diameter in inches) / 24.
For an 8.5-inch hole, rw = 0.354 ft. For 6.125-inch hole, rw = 0.255 ft.
Default assumes an 8.5-inch hole.
3. Fluid properties
Selecting a fluid type auto-fills the gradient and density. Choose "Custom" to enter
values directly.
Hydrostatic gradient of injection fluid. Used to compute pressure added by the fluid column
from surface to perforations.
Density of injection fluid. Used in the friction calculation. Converted internally to
lb/gal (÷ 7.481) to match the standard Reynolds and Fanning constants.
Viscosity at reservoir temperature. Auto-calculated from TBH via the McCain
fresh-water correlation (μ = 109.574 · T−1.12166, T in °F). Override for
non-water fluid or salinity-corrected values.
Water formation volume factor. Default 1.0 is appropriate for typical brines and rarely
deviates more than 1–2% for water.
4. Reservoir properties
Depth from surface to the top of the fluid column in the wellbore, measured during shut-in
conditions. From an acoustic fluid level survey (e.g., Echometer) or a wireline static survey
taken before the RAT. If the well is full to surface, enter 0.
Gradient of the static fluid column in the wellbore. Typically 0.43–0.46 psi/ft for water/brine.
Default 0.44 psi/ft is appropriate for typical produced water.
Radius at which Pe is assumed to apply. Conventional: 660 ft (40-acre), 933 ft
(160-acre), 1320 ft (320-acre). The calculation is relatively insensitive to re
since it appears inside ln(re/rw) — going from 500 to 1500 ft changes
k by only ~30%.
Net thickness actually taking fluid — not the total perforated interval. From a
spinner survey, sum the intervals showing measurable flow. If no spinner is available, use
net pay from log analysis.
Total perforated interval, for reference only. Not used in k, but used to compute fluid
entry efficiency (heff / hperf).
Dimensionless. Default 0 ⇒ result is the effective (skin-included) permeability from
the survey (current behavior). Enter a positive value to assume damage and infer the higher
intrinsic permeability: k = 141.2 · q · μ · B · (ln(re/rw) + s) /
(h · ΔP). Single-rate data cannot determine skin — this is an explicit
assumption; report s alongside k in any submittal.
5. Intermediate values (QC)
Pe (computed / entered)
—
—
Reynolds number, Re
—
—
Fanning friction factor, f
—
dimensionless
ΔPfriction
—
psi
Phydrostatic
—
psi
Pwf (bottomhole flowing)
—
psi
ΔP across formation
—
psi
ln(re / rw)
—
—
Fluid entry efficiency
—
heff / hperf
6. Results
Effective permeability, keff
—
141.2 · q · μ · B · (ln(re/rw) + s) / (h · ΔP), steady-state radial (s = 0 ⇒ skin-included)
Permeability-thickness, kh
—
mD-ft
Injectivity Index, II
—
bbl/d/psi
Specific injectivity, II/h
—
bbl/d/psi/ft
With assumed skin s = 0 (default), this is the effective (skin-included) permeability from the survey under steady-state radial flow. With a positive s entered above, it is the inferred intrinsic permeability corresponding to that assumption — single-rate data cannot determine skin, so any non-zero s should be reported alongside k.
7. Sensitivity — keff (mD) vs. Pe and heff
Columns: Pe at ±20% in 10% steps. Rows: heff at 0.50× to 1.50× in 25% steps. All other inputs (q, μ, B, re, rw, Pwf) held constant at base values, with skin held at the entered s across the matrix. Base case (center cell) highlighted; cells within ±50% of base k tinted lighter.
8. Methods, references, and caveats
- Darcy radial flow (steady-state, field units): k (mD) = 141.2 · q (bbl/d) · μ (cP) · B (RB/STB) · (ln(re/rw) + s) / (h (ft) · ΔP (psi)), with ΔP = Pwf − Pe and s = assumed skin (dimensionless; s = 0 ⇒ bare radial form).
- Bottomhole flowing pressure: Pwf = Psurf + Phydrostatic − ΔPfriction, with Phydrostatic = L · gradient.
- Fanning friction equation (field units): ΔPf (psi) = 5.50×10⁻⁶ · f · ρ · q² · L / di⁵, with f the Fanning friction factor, ρ in lb/gal (calculator converts the lb/ft³ input ÷ 7.481), q in bbl/d, L in ft, di in inches. Derived from ΔP = 2·f·ρ·v²·L/D; equal to the v-based form f·ρ·v²·L/(25.8·di). The equivalent lb/ft³ constant is 7.36×10⁻⁷.
- Reynolds number: Re = 11.05 · ρ · q / (μ · di), ρ in lb/gal, same units as friction. Equivalent to 1.48 · ρ(lb/ft³) · q / (di · μ) and to 92.1 · SG · q / (di · μ); the specific-gravity constant 92.1 must not be applied to lb/gal.
- Swamee-Jain explicit (Fanning): f = 0.0625 / [log10((ε/di)/3.7 + 5.74/Re0.9)]², valid for Re > 4000. Laminar fallback (Re ≤ 4000): f = 16/Re.
- Water viscosity (McCain 1990, fresh water at atmospheric P): μ (cP) = 109.574 · T (°F)−1.12166.
- References: Earlougher (1977), Advances in Well Test Analysis, SPE Monograph 5; Crane Technical Paper No. 410; Swamee & Jain (1976), "Explicit equations for pipe-flow problems"; McCain (1990), The Properties of Petroleum Fluids, 2nd ed.
- Effective vs intrinsic k: with s = 0 the result is effective (skin-included) permeability. Positive skin (damage) causes the s = 0 result to underestimate intrinsic k; negative skin (stimulation) causes overestimation. To resolve true skin, run a pressure transient analysis; entering a non-zero s in §4 applies the correction explicitly under that assumption — report the assumed s alongside k in any submittal.
- Steady-state assumption: requires stabilized rate and pressure at the time of the survey. If taken during transient conditions (recent rate change, recent startup or shut-in), keff will be biased. Allow 1–2 hours of stable injection before recording.
- Observed rate vs. monthly average: use the wellhead-flowmeter rate at the stabilized portion of the survey — not the monthly injection average from regulatory reports. Monthly averages smear over downtime, rate changes, and operational variability and paired with an instantaneous pressure give a meaningless result.
- Deviated wells: friction uses measured depth (correct); hydrostatic also currently uses measured depth (approximation). For wells >30° from vertical, hydrostatic should be computed from TVD. A future revision will support separate MD/TVD entry.
- Single-phase liquid: friction model assumes single-phase water flow. Multiphase, gassy, or compressible flow requires different methodology.
- Static fluid level (Mode B): assumes the static column has equilibrated. For recently shut-in wells, fluid level may still be rising — wait for stabilization before measuring.
Single Well ZEI Calculator
Single-well, screening-level Zone of Endangering Influence for a Class II UIC permit application: Bernard / Warner-Lear ΔP, endangering pressure, and volumetric radii, sized for a one-page screenshot.
Endangering pressure
Base of USDW, its fluid level, and gradient (0.433 = fresh water).
PUSDW = — psi
Top of injection-zone perforations (endangering-pressure datum).
Initial reservoir pressure at top perf — enter directly or as gradient × depth.
Pi = — psi
Injection fluid specific gravity — enter directly or as a fluid gradient (÷ 0.433).
SGi = —
ΔPc = PUSDW + (zi − zUSDW)·SGi·0.433 − Pi = —
Pc = — psi · ΔPc = — psi
Reservoir & fluid properties
Net thickness for the Bernard & volumetric equations — direct, or gross × N:G.
Reference only; calc uses net thickness.
Net effective porosity, percent.
Brine permeability for the Bernard equation — direct, air × multiplier, or Swanson (0.292·kair1.186).
kbrine = — mD
Reservoir T; sets μ (temperature-only).
Auto from T (McCain, ≈0.40 cP at 150°F); override for the cited 0.43 or a measured value.
≈3×10−⁶ /psi, water-saturated.
0 none; + damage; − stim.
Informational.
Dispersion term rdisp = r + 2.3·√(D·r).
Injection history & project design
Cumulative gross to date; drives the current volumetric radius.
Produced volumes (optional) — net-voidage reference only.
Historical net injection = — RBBL
Proposed maximum rate.
→ t = life × 8766 hr.
Key results
ZEI radius
—
—
Endangering ΔPc—
Endangering Pc—
Equiv. gradient, Pc/zi—
kh = — mD·ft · t = — hr
Equivalent gradient vs. fracture gradient (~0.7–0.8 psi/ft): if it approaches or exceeds fracture, USDW endangerment through a hydraulic conduit is unlikely regardless of rate.
Volumetric radius of injected fluid
Radius (ft)
+ dispersion (ft)
Current
—
—
End of project life
—
—
Current uses gross historical injection (see Injection history for net voidage). r = √(V·5.615·Bw/(π·H·ϕ)); dispersion per Warner & Lear (1977). Informational; not used in the ZEI.
ΔP vs. distance (Bernard / Warner-Lear)
ΔP(r,t) = (162.6·Q·μ)/(k·h) · [ log10( k·t / (ϕ·μ·ct·r²) ) − 3.32 + 0.87·s ]
| r (ft) | ΔP | New P | ZEI? |
|---|
| r (ft) | ΔP | New P | ZEI? |
|---|
References: (1) Warner, D.L., and Lehr, J.H., 1977. An Introduction to the Technology of Subsurface
Wastewater Injection. U.S. EPA, EPA/600/2-77/240, Ada, OK. (2) Matthews, C.S., and Russell, D.G., 1967.
Pressure Buildup and Flow Tests in Wells. SPE Monograph Volume 1. (3) Swanson, B.F., 1981. A Simple
Correlation Between Permeabilities and Mercury Capillary Pressures. JPT 33 (12): 2498–2504. SPE-8234-PA.
Methods, assumptions, and caveats
- Bernard / Warner-Lear log approximation (field units, t in hours): ΔP(r,t) = (162.6·Q·μ)/(k·h) · [log10(k·t/(ϕ·μ·ct·r²)) − 3.32 + 0.87·s]. Single-well, infinite-acting radial flow (Matthews & Russell 1967).
- Endangering pressure: Pc = PUSDW + (zi − zUSDW)·SGi·0.433; ΔPc = Pc − Pi. A ZEI exists only where the modeled ΔP reaches ΔPc.
- Volumetric radius: r = √(V·5.615·Bw/(π·H·ϕ)); dispersion rdisp = r + 2.3·√(D·r) (Warner & Lear 1977). Current case uses gross historical injection.
- Brine permeability (Swanson 1981): kbrine = 0.292·kair1.186 (SPE-8234-PA).
- Water viscosity (McCain, fresh water): μ = 109.574·T−1.12166, T in °F (≈0.40 cP at 150°F; editable).
- Screening scope: single well only; no superposition, faults, or transport. A rigorous transient model is built separately.