NSLLC Petroleum Toolkit

Arps Decline (Forecast & EUR)

Initial rate q_i (bbl/d)

Initial decline D_i (nominal, 1/yr)

b (0=exp, 0.5=hyp, 1=harm)

Forecast horizon (years)

Economic limit q_econ (bbl/d)

Terminal D_min (1/yr; 0 = none)

Log y-axis (rate plot) —

Rate (bbl/d) vs t (yr)

Cum Np (bbl) vs t (yr)

EUR

—

bbl

EUR

—

MMSTB

Economic life

—

q_final

—

bbl/d

Exp (b=0): q=q_i·exp(−D_it). Hyp: q=q_i/(1+b·D_it)^1/b. Harm (b=1): q=q_i/(1+D_it). With D_min: switches to exponential at D_min 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

Oil price ($/bbl, flat)

Gas price ($/Mcf, flat)

GOR (scf/bbl)

Operating & capital costs (WI basis)

OPEX fixed ($/month/well)

OPEX variable ($/bbl oil)

Discount rate (%/yr)

CAPEX ($M, at t=0)

Abandonment ($M, at ECL)

Ownership

Working Interest, WI (%)

Lease NRI (%)

Revenue Interest, RI (%) ?

Results

Gross oil

—

bbl

Net oil to RI

—

bbl

Gross gas EUR

—

MMcf

Net gas to RI

—

MMcf

Oil revenue

—

Gas revenue

—

Total OPEX (WI)

—

Peak cash exposure

—

Undisc net CF

—

NPV @ disc rate

—

Payout

—

Break-even oil

—

$/bbl

IRR

—

MOIC

—

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 · Q_oil · P_oil; Gas rev = RI · (Q_oil·GOR/1000) · P_gas; OPEX = WI · (12·Fixed·Δt + Q_oil · Variable); CF = Oil rev + Gas rev − OPEX. Cash-out at t=0: −WI·CAPEX. NPV = −WI·CAPEX + Σ CF_y/(1+d)^y. Project life ends at the earlier of (a) q_econ 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: ROI_undisc = cumCF / (WI·CAPEX), ROI_disc = 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.

Reservoir-condition CO₂ density (g/cc)

Mass

tonnes (t)

kilotonnes (kt)

megatonnes (Mt)

short tons

pounds (lb)

Standard volume (60°F, 14.696 psia)

scf

Mscf (10³ scf)

MMcf (10⁶ scf)

Bcf (10⁹ scf)

sm³

Reservoir-condition volume (uses ρ above)

bbl

m³

acre-ft

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 / ρ_res.

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.

Pressure (psia)

Temperature (°F)

ρ = — g/cc | — lb/ft³ | — kg/m³

μ = — cP | Phase: —

Density: Peng-Robinson cubic EOS (T_c=304.13 K, P_c=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)

G_CO₂ = A · h · ϕ · (1 − S_wirr) · ρ_CO₂ · E. Per Goodman et al. (2011) / DOE-NETL Carbon Storage Atlas methodology.

Area A (acres)

Net thickness h (ft)

Porosity ϕ (%)

S_wirr (%)

CO₂ density ρ (g/cc, res)

Storage efficiency E (fraction)

Injection rate (Mt/yr, for years calc)

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.

Reservoir-condition CO₂ density (g/cc)

Mass rate

Mt/yr

kt/yr

t/d

kg/s

Standard volume rate (60°F, 14.696 psia)

MMscf/d

Mscf/d

sm³/d

Reservoir volume rate (uses ρ above)

bbl/d

m³/d

Conversion basis as in Section 1. Mt/yr uses 365.25-day year. Reservoir m³ = mass / ρ_res.

Plume Radius (Volumetric Estimate)

Screening estimate assuming uniform radial displacement. Does NOT account for buoyancy, dissolution, residual trapping, or heterogeneity.

Cumulative CO₂ mass (Mt)

CO₂ density ρ (g/cc, res)

Net thickness h (ft)

Porosity ϕ (%)

S_wirr (%)

r_plume = — ft | — m

r = √[ (M / ρ_CO₂) / (π · h · ϕ · (1 − S_wirr)) ]. 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 (R_w) from R_t and ϕ via a formation factor (F = R_o/R_w) relationship, corrects R_w 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

Mode A — calculate gradient from BHT Mode B — enter gradient directly

Surface temperature (°F)

BHT (°F)

Total depth, TD (ft)

Target depth (ft)

Surface T

—

°F

Gradient

—

°F/100 ft

T at target depth

—

°F

2. Base case inputs

True resistivity, R_t (ohm-m)

Porosity, ϕ

Reference T, T_ref (°F) ?

3. Salinity correlation

Gen-9 NaCl (default) Schlumberger 1988 chart Active: Gen-9

4. Rock type / formation factor

Rock type (formation factor relationship)

F equation

5. Base case results

Formation factor, F

—

R_w at depth T

—

ohm-m

R_w at T_ref

—

ohm-m

NaCl salinity

—

ppm

Estimated TDS

—

ppm (NaCl-eq)

6. Implied R_t at reference salinities

R_t that would correspond to the indicated NaCl-equivalent salinity, holding ϕ, formation factor method, depth temperature, and T_ref 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.

R_t @ 10,000 ppm NaCl

—

ohm-m

R_t @ 3,000 ppm NaCl

—

ohm-m

7. Sensitivity — NaCl (ppm) vs. ϕ and formation factor method

R_t, depth temperature, and T_ref 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: R_w(T₂) = R_w(T₁) · (T₁ + 7) / (T₂ + 7), T in °F. Arps (1953).
Gen-9 NaCl (default): NaCl (ppm) = ROUND(5697.5 · R_w(T_ref)^−1.079, nearest 10). Empirical fit to the Schlumberger Gen-9 chart at T_ref = 75°F.
Schlumberger 1988 chart correlation: NaCl (ppm) = 10^{((3.562 − log₁₀(R_w(T_ref) − 0.0123)) / 0.955)}. From Schlumberger Log Interpretation Charts, 1988 edition, Gen-9.
Archie's law: F = R_o/R_w; R_w = R_t/F under fully water-saturated, clean (shale-free) conditions. Hydrocarbon presence or shaliness will bias R_w 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 → R_w at depth T = R_t/F → R_w at T_ref via Arps → NaCl via active correlation. All inputs are live; the sensitivity table recomputes on every change.

Total Compressibility (c_t)

Compute total reservoir compressibility c_t = c_rock + S_w·c_w + S_o·c_o 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, S_w (fraction)

Water saturation in the injection zone. For a water-saturated disposal zone (typical Class II injection into a brine aquifer or fully swept reservoir), S_w = 1.0. For a partially depleted reservoir with residual oil, use the actual S_w from log analysis or core data.

Oil saturation, S_o (fraction)

Residual oil saturation in the injection zone. For a clean disposal zone, S_o = 0. For a depleted producer being converted to injection, use the post-production residual S_or — typically 0.20–0.35 depending on the formation.

Rock compressibility, c_rock (1/psi)

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.

Water compressibility, c_w (1/psi)

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.

Oil compressibility, c_o (1/psi)

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 c_t when S_o = 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

c_t = c_rock + S_w × c_w + S_o × c_o

—

Total compressibility, c_t

—

Rock contribution

—

Water contribution (S_w·c_w)

—

Oil contribution (S_o·c_o)

—

4. Methods, references, and caveats

Total compressibility equation: c_t = c_rock + S_w·c_w + S_o·c_o. 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 c_rock ranges.
McCain (1990): The Properties of Petroleum Fluids, 2nd ed., PennWell Books. Source for c_w and c_o 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 c_t purposes.
High-salinity brines: for >100,000 ppm TDS, c_w 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

Surface injection pressure, P_surf (psi)

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.

Observed injection rate, q (bbl/d)

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 P_surf above. The well should have been injecting at this rate for at least 1–2 hours before the reading to ensure pressure has stabilized.

Bottomhole temperature, T_BH (°F)

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.

Survey date (optional)

Date of the RAT survey. Used in PDF/print reports only.

2. Well configuration

Tubing depth to top perfs, L (ft)

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.

Tubing OD / weight

Standard API tubing sizes. Selecting an OD/weight auto-fills the ID below. Choose "Custom" for non-standard tubing.

Tubing ID, d_i (inches)

Inside diameter of injection tubing. Auto-populates based on the tubing size selected above. Override for non-standard or worn tubing.

Tubing roughness, ε (inches)

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.

Wellbore radius, r_w (ft)

Radius of the wellbore at the perforations. Equals (hole diameter in inches) / 24. For an 8.5-inch hole, r_w = 0.354 ft. For 6.125-inch hole, r_w = 0.255 ft. Default assumes an 8.5-inch hole.

3. Fluid properties

Injection fluid type

Selecting a fluid type auto-fills the gradient and density. Choose "Custom" to enter values directly.

Injection fluid gradient (psi/ft)

Hydrostatic gradient of injection fluid. Used to compute pressure added by the fluid column from surface to perforations.

Fluid density, ρ (lb/ft³)

Density of injection fluid. Used in the friction calculation. Converted internally to lb/gal (÷ 7.481) to match the standard Reynolds and Fanning constants.

Water viscosity, μ (cP)

Viscosity at reservoir temperature. Auto-calculated from T_BH via the McCain fresh-water correlation (μ = 109.574 · T^−1.12166, T in °F). Override for non-water fluid or salinity-corrected values.

Formation volume factor, B_w (RB/STB)

Water formation volume factor. Default 1.0 is appropriate for typical brines and rarely deviates more than 1–2% for water.

4. Reservoir properties

Mode A — direct P_e Mode B — from static fluid level (default) Mode C — regional gradient

Static fluid level from surface, z_fl (ft)

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.

Static column gradient (psi/ft)

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.

Drainage radius, r_e (ft)

Radius at which P_e is assumed to apply. Conventional: 660 ft (40-acre), 933 ft (160-acre), 1320 ft (320-acre). The calculation is relatively insensitive to r_e since it appears inside ln(r_e/r_w) — going from 500 to 1500 ft changes k by only ~30%.

Effective net thickness, h_eff (ft)

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.

Perforated interval, h_perf (ft)

Total perforated interval, for reference only. Not used in k, but used to compute fluid entry efficiency (h_eff / h_perf).

Assumed skin factor, s

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(r_e/r_w) + 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)

P_e (computed / entered)

—

Reynolds number, Re

—

Fanning friction factor, f

—

dimensionless

ΔP_friction

—

psi

P_hydrostatic

—

psi

P_wf (bottomhole flowing)

—

psi

ΔP across formation

—

psi

ln(r_e / r_w)

—

Fluid entry efficiency

—

h_eff / h_perf

6. Results

Effective permeability, k_eff

—

141.2 · q · μ · B · (ln(r_e/r_w) + 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 — k_eff (mD) vs. P_e and h_eff

Columns: P_e at ±20% in 10% steps. Rows: h_eff at 0.50× to 1.50× in 25% steps. All other inputs (q, μ, B, r_e, r_w, P_wf) 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(r_e/r_w) + s) / (h (ft) · ΔP (psi)), with ΔP = P_wf − P_e and s = assumed skin (dimensionless; s = 0 ⇒ bare radial form).
Bottomhole flowing pressure: P_wf = P_surf + P_hydrostatic − ΔP_friction, with P_hydrostatic = L · gradient.
Fanning friction equation (field units): ΔP_f (psi) = 5.50×10⁻⁶ · f · ρ · q² · L / d_i⁵, 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, d_i in inches. Derived from ΔP = 2·f·ρ·v²·L/D; equal to the v-based form f·ρ·v²·L/(25.8·d_i). The equivalent lb/ft³ constant is 7.36×10⁻⁷.
Reynolds number: Re = 11.05 · ρ · q / (μ · d_i), ρ in lb/gal, same units as friction. Equivalent to 1.48 · ρ(lb/ft³) · q / (d_i · μ) and to 92.1 · SG · q / (d_i · μ); the specific-gravity constant 92.1 must not be applied to lb/gal.
Swamee-Jain explicit (Fanning): f = 0.0625 / [log₁₀((ε/d_i)/3.7 + 5.74/Re^0.9)]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), k_eff 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.

NSLLC Petroleum Toolkit

Unit Converter

Water Viscosity (McCain, 1990)

Hydrostatic Pressure

API Gravity ↔ Specific Gravity

Gas Formation Volume Factor (B_g)

Oil Formation Volume Factor (B_o, Standing 1947)

Cement Volume (Annular)

Original Oil in Place (Volumetric)

Original Gas in Place (Volumetric)

BOE Converter

Arps Decline (Forecast & EUR)

Single-Well Economics

CO₂ Mass ↔ Volume Conversions

CO₂ Density, Viscosity & Phase

Storage Capacity (DOE/NETL Volumetric)

CO₂ Injection Rate Conversions

Plume Radius (Volumetric Estimate)

Quick Reference Constants

Resistivity-Porosity Salinity Calculator

Total Compressibility (c_t)

Darcy Permeability (RAT)

Single Well ZEI Calculator

Unit Converter

Water Viscosity (McCain, 1990)

Hydrostatic Pressure

API Gravity ↔ Specific Gravity

Gas Formation Volume Factor (Bg)

Oil Formation Volume Factor (Bo, Standing 1947)

Cement Volume (Annular)

Original Oil in Place (Volumetric)

Original Gas in Place (Volumetric)

BOE Converter

Arps Decline (Forecast & EUR)

Single-Well Economics

CO₂ Mass ↔ Volume Conversions

CO₂ Density, Viscosity & Phase

Storage Capacity (DOE/NETL Volumetric)

CO₂ Injection Rate Conversions

Plume Radius (Volumetric Estimate)

Quick Reference Constants

Resistivity-Porosity Salinity Calculator

Total Compressibility (ct)

Darcy Permeability (RAT)

Single Well ZEI Calculator

Gas Formation Volume Factor (B_g)

Oil Formation Volume Factor (B_o, Standing 1947)

Total Compressibility (c_t)