Petroleum engineering workflow guides
Each guide combines source-verified context, a worked calculation, method-selection advice, failure checks, and linked calculators. Use the article to frame the engineering question, then run the calculator with your own documented inputs.
Drilling hydraulics and rheology
Why annular velocity changes when the hole gets wider
At a fixed volumetric flow rate, average annular velocity decreases as the flow area increases. Use the difference between hole and pipe cross-sectional areas, not the hole area alone.
Worked example + interactive comparison →Bingham plastic versus power law versus Herschel Bulkley
Bingham plastic uses a yield stress plus a linear viscous term; power law uses a curved shear-rate response without a yield intercept; Herschel–Bulkley combines a yield term with a power-law term.
Worked example + interactive comparison →How to fit Herschel Bulkley parameters from viscometer readings
Fit Herschel–Bulkley to calibrated shear stress versus shear rate, not to unconverted dial readings. Instrument geometry, spring and rotor/bob configuration determine the conversion.
Worked example + interactive comparison →Annular pressure loss through several hole sections
Calculate frictional pressure loss for each interval using its own geometry, length, flow and rheology. Add compatible losses along the same path; do not average diameters before solving.
Worked example + interactive comparison →Darcy versus Fanning friction factors in drilling calculations
For matching definitions, the Darcy friction factor is four times the Fanning factor. Use a factor with the pressure-loss equation that defines it.
Worked example + interactive comparison →What pipe eccentricity changes in annular flow
An off-center pipe creates a narrow gap and a wide gap. Average annular area is unchanged, but velocity distribution, shear and the pressure needed to deliver a given rate can change.
Worked example + interactive comparison →Explore yield stress and the unyielded annular region
A yield-stress fluid can contain a region with stress below the yield threshold. Such material may move as a plug; unyielded does not automatically mean stationary.
Worked example + interactive comparison →When a laminar annular model stops being appropriate
A laminar solution can be evaluated mathematically at a rate where its physical assumptions are no longer suitable. Check the relevant regime indicator before interpreting its pressure prediction.
Worked example + interactive comparison →Pressure depth and well control fundamentals
Convert mud weight to pressure gradient with units shown
In US field units, multiply mud weight in ppg by 0.052 to obtain a hydrostatic gradient in psi/ft. Multiply that gradient by the vertical fluid height to obtain a pressure difference.
Worked example + interactive comparison →Gauge versus absolute pressure in petroleum calculations
Gauge pressure is measured relative to the local atmosphere. Absolute pressure is measured relative to vacuum. Convert with Pabs = Pgauge + Patm before using a gas equation of state.
Worked example + interactive comparison →Calculate hydrostatic pressure across two fluid columns
Add the hydrostatic contribution of each fluid using that fluid's density and vertical height. A two-column calculation is a sum of pressure increments, not an average of densities without length weighting.
Worked example + interactive comparison →Why shoe depth matters in a MAASP calculation
A shoe-based MAASP calculation evaluates pressure at the casing shoe. Its depth denominator must be shoe TVD, and its density allowance must use the current fluid above that shoe.
Worked example + interactive comparison →SIDPP versus SICP what each pressure represents
SIDPP and SICP are pressures at different flow paths. Under the usual static assumptions, their difference reflects different hydrostatic columns; substituting casing pressure for drillpipe pressure can distort a kill-density calculation.
Worked example + interactive comparison →Initial versus final circulating pressure on a worksheet
Initial circulating pressure adds stabilized SIDPP to a recorded slow-rate friction pressure. Final circulating pressure scales that friction reference by kill mud weight divided by original mud weight, under the worksheet assumptions.
Worked example + interactive comparison →Explore how pressure equivalent density changes with depth
A fixed pressure corresponds to a larger equivalent density increment at shallow depth. The relationship is ΔMW = ΔP/(0.052 × TVD), so doubling depth halves the equivalent increment.
Worked example + interactive comparison →Hydrostatic pressure versus bottomhole pressure
Hydrostatic pressure is the contribution of the fluid column. Bottomhole pressure is the pressure at a location and can include surface pressure and dynamic terms as well as hydrostatic head.
Worked example + interactive comparison →Cementing volumes and well geometry
Annular capacity versus annular volume
Annular capacity is volume per unit length. Annular volume is capacity multiplied by the measured length of the interval with that geometry.
Worked example + interactive comparison →Cement slurry yield versus slurry density
Slurry yield is the volume of mixed slurry produced per sack of cement. Slurry density is mass per slurry volume. Density alone cannot determine how many sacks produce a required volume.
Worked example + interactive comparison →Calculate mixing water after rounding cement sacks
Calculate mixing water from the whole sacks that will actually be mixed. Using the fractional theoretical sack demand understates water for a batch rounded upward.
Worked example + interactive comparison →How to combine casing open hole and shoe track volumes
Calculate cased-hole annulus, open-hole annulus and shoe-track volumes as separate nonoverlapping entries. Their boundaries and diameters differ, even when the same slurry fills them.
Worked example + interactive comparison →Excess cement volume versus hole enlargement
A percentage increase in hole diameter is not the same percentage increase in annular volume. Annular area depends on the difference of squared diameters.
Worked example + interactive comparison →Measured depth and diameter checks for a volume calculation
Volume uses measured interval length and the actual enclosing and enclosed diameters. TVD is appropriate for hydrostatic head, but it generally understates volume in a deviated interval.
Worked example + interactive comparison →Explore how hole diameter affects cement demand
Hole diameter can strongly change cement demand because the open-hole area grows with diameter squared while casing displacement stays fixed.
Worked example + interactive comparison →Barrels cubic feet and gallons in cement calculations
A petroleum barrel is 42 US gallons. Using 231 in³ per US gallon gives 5.614583333 ft³ per barrel. These are volume conversions, independent of slurry density.
Worked example + interactive comparison →Reservoir flow and well productivity
Porosity versus permeability why storage is not flow capacity
Porosity describes void volume; permeability describes how readily a connected pore system transmits fluid. One cannot be inferred uniquely from the other without rock-specific evidence.
Worked example + interactive comparison →Steady state transient and pseudosteady state flow
Steady state has an unchanging pressure distribution; transient flow has an evolving pressure disturbance; pseudosteady state has an approximately stabilized spatial shape while average reservoir pressure declines.
Worked example + interactive comparison →Calculate radial pressure drop with skin included
In the stated steady radial model, skin adds to the dimensionless logarithmic resistance. Positive skin reduces rate for a fixed drawdown or increases required drawdown for a fixed rate.
Worked example + interactive comparison →Why well radius and drainage radius affect productivity differently
Well radius and drainage radius enter the radial resistance logarithm through their ratio. Their percentage changes can have equal algebraic effects, although their physical meanings and feasible changes differ.
Worked example + interactive comparison →Horizontal versus vertical well productivity under stated assumptions
Horizontal and vertical productivity comparisons require matched rock, fluid and drainage assumptions. A longer well can improve access, but anisotropy, thickness and drainage geometry affect the gain.
Worked example + interactive comparison →Fit permeability from core flood pressure and rate data
The site's permeability calibration fits log10(k) against porosity from supplied core pairs. It does not directly regress a core-flood pressure–rate curve; convert such measurements to permeability first using their documented geometry and fluid properties.
Worked example + interactive comparison →Explore the permeability viscosity and pressure tradeoff
Within single-phase Darcy flow, rate scales with permeability and pressure drop and inversely with viscosity and flow length. The tradeoff holds only while geometry and the linear-flow assumptions are retained.
Worked example + interactive comparison →Darcy versus Forchheimer when inertia changes the equation
Darcy–Forchheimer adds a velocity-squared inertial resistance to the viscous Darcy term. At low velocity it approaches Darcy behavior; at higher velocity a linear Darcy extrapolation overpredicts flow for a fixed gradient.
Worked example + interactive comparison →Volumetrics material balance and displacement
Build a volumetric gas in place calculation from a rock volume
Build volumetric gas in place by calculating bulk rock volume, connected pore volume and gas-filled pore volume, then dividing by Bg on a compatible reservoir-to-standard volume basis.
Worked example + interactive comparison →Volumetric versus material balance estimates of oil in place
Volumetrics estimates initial pore occupancy from geometry and rock properties. Material balance estimates an inventory consistent with observed fluid withdrawal, pressure-dependent expansion and supported influx assumptions.
Worked example + interactive comparison →Net to gross gross thickness and net pay in volumetrics
Gross thickness describes the whole interval. Net-to-gross selects the fraction counted as net rock; net pay is the resulting thickness under the stated cutoffs. Use either net pay or gross thickness times net-to-gross, once.
Worked example + interactive comparison →Gas expansion factor versus gas formation volume factor
Gas expansion factor is the reciprocal of gas formation volume factor only when the volume units and reference conditions are complementary. Always write the numerator and denominator units.
Worked example + interactive comparison →What water influx changes in a material balance interpretation
Water influx supplies reservoir volume and pressure support. Ignoring it can force a material-balance calculation to attribute that support incorrectly to hydrocarbon inventory or expansion.
Worked example + interactive comparison →Buckley Leverett breakthrough pore volumes explained
Buckley–Leverett breakthrough pore volumes follow from a fractional-flow shock construction. The shock speed is a tangent slope, not simply the fractional-flow value at an arbitrarily selected saturation.
Worked example + interactive comparison →Explore gas in place sensitivity to porosity and saturation
For fixed geometry and Bg, volumetric gas in place is proportional to porosity and to 1 − Sw. Saturation sensitivity depends on the gas-filled fraction, not on Sw alone.
Worked example + interactive comparison →Why one pressure point cannot establish a reservoir model
One pressure state provides too little information to distinguish inventory, influx, PVT error and other reservoir mechanisms. A balance can have multiple unknowns even when its arithmetic has one equation.
Worked example + interactive comparison →Decline curves and forecasting
Exponential hyperbolic and harmonic decline explained
Exponential, hyperbolic and harmonic decline are members of the Arps family. Exponential has constant nominal decline; hyperbolic decline decreases with time; harmonic is the b = 1 endpoint.
Worked example + interactive comparison →How the hyperbolic b factor changes a forecast
The hyperbolic b factor controls how quickly nominal decline decreases. It is a fitted shape parameter, not an independent measure of reservoir quality or a guarantee of a long productive tail.
Worked example + interactive comparison →Calculate cumulative production from a decline curve
Cumulative production is the time integral of rate. It is not the final rate multiplied by the entire forecast duration unless rate is constant.
Worked example + interactive comparison →Why a decline forecast needs an end date and economic assumptions
A decline curve needs a defined end date or stopping condition before cumulative production has a useful forecast meaning. Economic and operating assumptions determine whether its late-time output is relevant.
Worked example + interactive comparison →Modified hyperbolic decline and the terminal decline switch
Modified hyperbolic decline switches to an exponential tail when instantaneous nominal decline reaches a chosen terminal value. Continuity requires carrying the rate at the switch into the exponential segment.
Worked example + interactive comparison →Stretched exponential Duong and Arps choosing a decline model
Arps, stretched exponential and Duong forms describe different empirical curve shapes and time behavior. Model choice needs the flow regime, fitting interval and prediction checks, not just the smallest in-sample residual.
Worked example + interactive comparison →Explore the same decline curve on monthly and annual time bases
The same exponential curve can be expressed per day, month or year if nominal decline and elapsed time are transformed together. The dimensionless product Dt must remain unchanged.
Worked example + interactive comparison →Preparing production data before a decline study
Prepare production data by preserving dates, volumes, active days and operating events. A missing value, a shut-in and a measured zero are different observations and should not be silently treated alike.
Worked example + interactive comparison →Petrophysics saturation and rock properties
Effective versus total porosity in saturation calculations
Total porosity counts the selected total pore volume; effective porosity describes the connected or interpreted effective pore space on the chosen method. A saturation model must use the porosity basis for which its parameters were established.
Worked example + interactive comparison →Why a calculated water saturation can exceed one
An Archie result above one is a diagnostic inconsistency under the supplied assumptions. Do not clip it to one before checking resistivity, porosity, units, temperature basis and model applicability.
Worked example + interactive comparison →Water resistivity temperature basis in a saturation workflow
Water resistivity must represent the water at the temperature basis required by the saturation interpretation. A surface-temperature Rw cannot automatically be used as a formation-temperature value.
Worked example + interactive comparison →Clean sand versus shaly sand choosing a saturation model
Use a clean-rock saturation model only where its electrical assumptions are appropriate. Conductive shale can contribute current that Archie would otherwise attribute to connected water.
Worked example + interactive comparison →Sonic porosity and matrix transit time assumptions
Sonic porosity depends on the selected transit-time model and matrix and fluid assumptions. A matrix transit time is a lithology-related model input, not a universal rock constant.
Worked example + interactive comparison →Capillary pressure versus relative permeability
Capillary pressure describes a phase-pressure difference; relative permeability describes phase mobility relative to a reference permeability. Both can depend on saturation, but they are different physical quantities.
Worked example + interactive comparison →Explore saturation curve parameters without changing the rock data
A saturation-curve parameter changes a selected model's shape; it does not change the underlying rock measurements. Keep observed points fixed while comparing parameter choices.
Worked example + interactive comparison →Gassmann fluid substitution what the inputs represent
Gassmann fluid substitution relates dry-frame, mineral and fluid bulk moduli with porosity under its low-frequency connected-pore assumptions. It does not infer all those properties from one sonic log.
Worked example + interactive comparison →Black oil and gas PVT
Reservoir barrels versus stock tank barrels
Reservoir barrels describe oil volume at reservoir conditions. Stock-tank barrels describe the associated stock-tank oil. Oil formation volume factor Bo is the ratio between those specified volumes.
Worked example + interactive comparison →Standing versus Vasquez Beggs comparing compatible PVT inputs
Standing and Vasquez–Beggs comparisons require compatible pressure, temperature, gas-gravity and oil-gravity definitions. A difference between two correlations is not an accuracy ranking without suitable independent PVT data.
Worked example + interactive comparison →Bubble point versus dew point for petroleum fluids
At a specified temperature, bubble pressure marks the onset of vapor from liquid; dew pressure marks the onset of liquid from vapor. Mixture composition and the path through state space determine which boundary is encountered.
Worked example + interactive comparison →Gas gravity API gravity and specific gravity
Gas gravity is relative to a specified gas reference, commonly air. API gravity transforms liquid specific gravity at its reference condition. The two scales describe different properties.
Worked example + interactive comparison →Calculate gas density with absolute pressure and temperature
Calculate gas density using absolute pressure, absolute temperature, molecular weight and a compatible Z factor. Gauge pressure and Celsius cannot be inserted directly into an absolute gas-law expression.
Worked example + interactive comparison →Gas formation volume factor and expansion factor worked together
Gas formation volume factor can be derived from the ratio of reservoir and standard gas volumes for the same amount. Its reciprocal gives the complementary expansion factor after units are matched.
Worked example + interactive comparison →Explore gas Z correlations over reduced pressure
A gas Z comparison evaluates specific correlations at matched reduced pressure and temperature. Reduced variables depend on the selected pseudocritical properties, which are themselves model inputs.
Worked example + interactive comparison →Dead oil versus live oil viscosity in a correlation workflow
Dead-oil viscosity excludes dissolved gas on the stated reference basis. Live-oil viscosity includes the effect of solution gas through a specified correlation and phase condition.
Worked example + interactive comparison →Production inflow and surface facilities
Productivity index versus production rate
Productivity index is rate per pressure drawdown on a stated model and volume basis. Production rate also depends on the available drawdown; PI alone is not a rate forecast.
Worked example + interactive comparison →Gas deliverability pressure squared versus pseudopressure
Pressure-squared gas deliverability approximates gas-property behavior with a fitted relation. Pseudopressure instead integrates pressure-dependent viscosity and Z. Their coefficients and pressure variables are not interchangeable.
Worked example + interactive comparison →Actual pipe velocity versus an erosional screening limit
Actual pipe velocity is local volumetric rate divided by pipe area. An API RP 14E-style erosional velocity is an empirical screening value based on mixture density and an assumed C factor; they answer different questions.
Worked example + interactive comparison →Mixture density and gas volume basis in flowline calculations
A no-slip mixture density weights phase densities by local volumetric fractions. Standard gas volume is not a local phase volume and must be converted before it is used in that weighting.
Worked example + interactive comparison →Separator gas capacity versus liquid retention time
Separator gas capacity limits gas disengagement under a selected sizing relation. Liquid retention time is a separate volume-to-throughput constraint. Passing one check does not establish that the other is satisfied.
Worked example + interactive comparison →Residence time versus retention volume in a vessel
Residence or retention time in a simple vessel calculation is effective occupied volume divided by volumetric throughput. The volume and rate must refer to the same phase and local conditions.
Worked example + interactive comparison →Explore how pipe diameter changes velocity and friction screening
At fixed local volumetric rate, pipe velocity scales as diameter to the minus two. A frictional pressure-drop comparison also needs Reynolds number, relative roughness and a compatible friction factor.
Worked example + interactive comparison →What an inflow curve cannot tell you about a producing system
An inflow curve describes reservoir delivery versus flowing bottomhole pressure. The producing-system rate also needs an outflow relation and compatible boundary conditions.
Worked example + interactive comparison →Geomechanics and hydraulic fracturing
Effective stress versus total stress and the Biot coefficient
Total stress includes the overall load; effective stress subtracts the pore-pressure contribution under a stated convention. For an isotropic Biot model with compression positive, σ′ = σ − αp.
Worked example + interactive comparison →Mohr Coulomb failure envelopes with worked stress inputs
A Mohr–Coulomb envelope compares shear stress with cohesion plus effective normal stress times friction coefficient. The site's stress-components calculator resolves plane stresses; the strength envelope is an additional specified comparison.
Worked example + interactive comparison →Minimum and maximum hoop stress around a wellbore
Hoop stress varies around a wellbore because far-field stresses are redistributed by the cavity and boundary pressure. Minimum and maximum values require a consistent effective-stress and angular convention.
Worked example + interactive comparison →Carter leakoff coefficient time and area bases
Carter leakoff volume scales with exposed area and the square root of exposure time, plus any specified spurt term. The area must use the same face-count convention as the equation.
Worked example + interactive comparison →Leakoff spurt loss and fracture efficiency
Leakoff and spurt are fluid-loss terms. Fracture efficiency compares retained fracture volume with injected volume under a stated fluid balance; it is not determined by a leakoff coefficient alone.
Worked example + interactive comparison →Fracture conductivity versus dimensionless conductivity
Fracture conductivity is permeability times fracture width. Dimensionless conductivity divides that quantity by a reservoir permeability–length scale, so the same fracture can have different dimensionless significance in different reservoirs.
Worked example + interactive comparison →Explore the square root of time in Carter leakoff
The square root of exposure time creates a declining leakoff rate for a fixed exposed area. Volume keeps increasing, but each additional minute adds less time-dependent loss.
Worked example + interactive comparison →Vertical versus deviated wellbore stress assumptions
A deviated well requires stresses transformed into its local coordinate system before wall-stress and failure calculations. A vertical-well formula does not automatically account for orientation or shear coupling.
Worked example + interactive comparison →Compositional thermodynamics and phase behavior
Peng Robinson versus SRK on the same supported mixture
Peng–Robinson and SRK use different cubic equations and attraction functions. Compare them at the same feed, pressure, temperature, component constants and interaction assumptions before interpreting phase-split differences.
Worked example + interactive comparison →Phase fraction versus phase composition in a flash result
Phase fraction tells how much of each phase exists. Phase composition tells what each phase contains. A vapor mole fraction β is not the methane mole fraction in the vapor.
Worked example + interactive comparison →Bubble dew and critical regions on a phase envelope
A fixed-mixture phase envelope connects bubble and dew boundaries in pressure–temperature space. Near the critical region, phase distinctions shrink and a numerical branch needs careful interpretation.
Worked example + interactive comparison →Why phase stability is different from solver convergence
Convergence means an iterative calculation satisfied its numerical stopping rules. Phase stability asks whether the proposed equilibrium can lower its Gibbs energy by forming another phase. One does not automatically imply the other.
Worked example + interactive comparison →PT PH and PS flash specifications explained
A PT flash specifies pressure and temperature. A PH flash specifies pressure and enthalpy and solves for temperature. A PS flash specifies pressure and entropy under its stated energy model.
Worked example + interactive comparison →Characterizing a C7 plus fraction for a flash model
A C7+ assay fraction is a lump of many compounds. Characterization assigns a supported pseudocomponent or distribution from measured fraction properties and explicit correlations; it does not identify a unique molecular composition.
Worked example + interactive comparison →Explore separator pressure and phase split on one synthetic feed
Separator pressure changes phase equilibrium and how material is allocated between gas and remaining liquid. In a train, the downstream feed is the retained upstream liquid, not the original feed reused at every stage.
Worked example + interactive comparison →Calibrating heavy end PVT parameters without hiding residuals
A heavy-end calibration should preserve measured targets, parameter bounds and residuals at every state. A fitted interaction parameter is a model adjustment, not a newly measured molecular property.
Worked example + interactive comparison →Multiphase flow thermal behavior and flow assurance
Holdup versus flowing gas fraction
Flowing gas fraction is based on phase volumetric rates. Gas holdup is the fraction of local pipe volume occupied by gas. They coincide only under a compatible no-slip assumption.
Worked example + interactive comparison →Hydrostatic frictional and acceleration pressure terms
A pipe pressure balance can include elevation, wall friction and acceleration. Their signs depend on flow direction and the selected boundary-to-boundary path.
Worked example + interactive comparison →Ramey wellbore temperature profiles and heat transfer assumptions
A Ramey-style wellbore temperature model balances flowing-fluid heat capacity with heat transfer through the well and transient conduction into the formation. Its result depends on flow duration and the chosen thermal resistances.
Worked example + interactive comparison →Water hammer versus a steady pressure loss calculation
Water hammer is a transient wave caused by changing flow. A steady friction calculation cannot predict its propagation, reflection or closure-time response.
Worked example + interactive comparison →Hydrate onset versus wax appearance in a flow assurance model
Hydrate onset and wax appearance describe different phase-equilibrium problems. Hydrates involve water and gas guests in a solid lattice; wax involves crystallizing heavy hydrocarbon material.
Worked example + interactive comparison →Why thermal history changes a shut in and restart calculation
Formation temperature carries memory of earlier heat transfer. A shut-in and restart calculation can therefore differ from a fresh calculation with the same current flow rate and initial undisturbed temperature.
Worked example + interactive comparison →Explore gas slip and its effect on a thermal pressure profile
Gas slip changes phase occupancy and in-situ density, which can feed back into pressure and thermal behavior. A slip closure is an additional model assumption, not a consequence of equilibrium phase fraction alone.
Worked example + interactive comparison →Mesh convergence and residuals in an annular CFD calculation
A small nonlinear residual shows that a discrete system was solved. Mesh convergence asks whether a quantity of interest approaches a stable value as spatial resolution improves. These checks address different errors.
Worked example + interactive comparison →Foundation lessons and broader workflow guides
Well Control Calculation Workflow
A source-checked well control calculation workflow for hydrostatic pressure, kill mud weight, initial circulating pressure, final circulating pressure, and MAASP checks.
Drilling Hydraulics Formulas
A drilling hydraulics formula guide for ECD, annular pressure loss, annular velocity, pump output, and pressure-window checks.
Reservoir Engineering Formula Guide
A reservoir engineering formula guide for Darcy flow, straight-line productivity index, Vogel IPR, material balance, and original oil in place checks.
Petroleum PVT Calculator Guide
A petroleum PVT calculator guide for gas formation volume factor, oil formation volume factor, real-gas density, API gravity, and reservoir-to-surface volume conversion checks.
Joshi Horizontal Well Productivity Guide
A source-backed guide to the Joshi horizontal well productivity equation, drainage geometry, anisotropy, effective radius, skin, and the limits of steady-state inflow screening.
Shaly Sand Water Saturation Guide
A practical comparison of Indonesian, Archie, and Simandoux water-saturation calculations for resistivity logs, with input checks for shale volume, shale resistivity, porosity, and water resistivity.
Annular Hydraulics and Velocity Guide
A drilling annular hydraulics guide connecting flow rate, annular geometry, average velocity, hole-cleaning limits, pump output, pressure loss, and equivalent circulating density.
Black-Oil PVT Correlation Guide
A black-oil PVT correlation guide for Vasquez-Beggs solution gas-oil ratio, bubble point, formation volume factors, gas properties, and Beggs-Robinson oil viscosity checks.
API RP 14E Erosional Velocity Guide
A careful API RP 14E erosional-velocity workflow covering mixture density, empirical C factor, actual velocity, utilization, pipe sizing, and the equation's documented screening limitations.
Hydraulic Fracture Carter Leakoff Guide
A hydraulic-fracturing leakoff guide for Carter square-root-time fluid loss, spurt loss, exposed area, time basis, fluid balance, fracture efficiency, and model limitations.
How to Calculate Plateau Pressure for Water Influx
Learn how to calculate plateau pressure from reservoir pressure history and use pressure-step increments in van Everdingen-Hurst water influx calculations.
TVD vs Measured Depth in Pressure and Volume Calculations
Choose TVD or measured depth for hydrostatic pressure, annular volume and friction, with a well diagram, interactive examples and calculator links.
ECD vs EMW vs Mud Weight: Understanding the Pressure Budget
Compare mud weight, ECD and surface-pressure EMW with a pressure diagram, worked calculations and an interactive pressure budget at a stated TVD.
How Archie Exponents Change Water Saturation
Explore cementation exponent m and saturation exponent n with an Archie sensitivity table, worked example, pore diagram and interactive controls.
Linear vs Radial Darcy Flow: Choosing the Geometry
Choose a linear or radial Darcy model using flow diagrams, unit-aware worked examples and an interactive permeability comparison linked to both calculators.
Calculate Cement Volume and Sacks Across Multiple Well Sections
Build a section-by-section cement volume ledger, convert barrels to slurry sacks and mixing water, and explore excess and yield with a worked example.
Nominal vs Effective Decline: Monthly and Annual Examples
Convert effective annual decline to nominal daily decline for an exponential forecast, with monthly examples, a tangent diagram and an interactive rate curve.
Z Factor vs Gas Compressibility Coefficient
Separate dimensionless Z from gas compressibility cg using a synthetic isothermal Z curve, signed pressure derivatives, a worked example and interactive slope controls.
Vogel vs Straight-Line IPR: Choosing the Model
Compare Vogel and linear inflow assumptions, bubble-point regimes and normalized curves, with an interactive pressure-ratio slider and a 700 versus 500 STB/day example.
What a Compositional Flash Calculation Solves
Follow a hydrocarbon PT flash from feed to liquid and vapor, with a six-component balance ledger, worked mole allocations and an interactive phase-split explorer.
OOIP, OGIP, Recoverable Volume and Reserves: The Difference
Trace rock volume to oil or gas in place, separate an assumed recovery fraction from reserves classification, and work a volumetric OGIP example with clear units.
Fracture Gradient vs Fracture Pressure and Evaluation Depth
Build a treatment-pressure ledger from surface to fracture entry, distinguish pressure from a depth-normalized gradient, and explore friction at a defined TVD.
Beggs–Brill vs Homogeneous Flow: What the Models Assume
Compare liquid holdup, no-slip fraction and pressure-loss components on the same short gas-liquid segment, with matched inlet conditions and an interactive model comparison.